**Exhibit 99.3**

 

**MANAGEMENT’S DISCUSSION AND ANALYSIS AND RESULTS OF OPERATIONS**

** **

**For the Fiscal Year Ended December 31, 2007**

 

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Management’s Discussion andAnalysis

 

This management’s discussionand analysis (“MD&A”) is the Trust management’s analysis of its financialperformance and significant trends or external factors that may affect futureperformance. It is dated February 13, 2008 and should be read inconjunction with the audited consolidated financial statements for the yearended December 31, 2007 and the audited consolidated financial statementsand MD&A for the year ended December 31, 2006 and MD&A for thequarters ended March 31, 2007, June 30, 2007, September 30, 2007as well as the Trust’s Annual Information Form.

 

The MD&A containsforward-looking statements and readers are cautioned that the MD&A shouldbe read in conjunction with the Trust’s disclosure under “Forward-LookingStatements” included at the end of this MD&A.

 

Non-GAAP Measures

 

Historically, management usedthe non-GAAP measure Cash Flow or cash flow from operations to analyzeoperating performance, leverage and liquidity. We have now chosen to utilizethe GAAP measure cash flow from operating activities instead of Cash Flow.There are two differences between the two measures; positive or negativechanges in non-cash working capital and the deduction of expenditures on siterestoration and reclamation as they appear on the Consolidated Statements ofCash Flows. Although management feels that Cash Flow is a valued measure offunds generated by the Trust during the reported year, we have changed ourdisclosure to only discuss the GAAP measure in the MD&A in order to avoidany potential confusion by readers of our financial information and in ouropinion, to more fully comply with the intent of certain regulatoryrequirements.

 

Our historical measure of CashFlow reflected revenues and costs for the reported year. This amount, however,comprised accruals for at least one month of revenue and approximately twomonths of costs. The oil and gas industry is designed such that revenues aretypically collected on the 25th day of the month following theactual production month. Royalties are typically paid two months following theactual production month and operating costs are paid as the invoices arereceived. This can take several months; however, most invoices for operatedproperties are paid within approximately two months of the production month. Inthe event that commodity prices and or volumes have changed significantly fromthe last month of the previous reporting period over the last month of thecurrent reporting period, a difference could occur between cash flow fromoperating activities and our historical non-GAAP measure of Cash Flow or cashflow from operations. Additionally, periods where the Trust spends asignificant amount on site restoration and reclamation would result in adifference between cash flow from operating activities and Cash Flow.

 

At the time of writing thisMD&A, substantially all revenues have been collected for the productionperiod of December 2007. Management performs analysis on the amountscollected to ensure that the amounts accrued for December are accurate.Analysis is also performed regularly on royalties and operating costs to ensurethat amounts have been properly accrued.

 

Management uses certain keyperformance indicators (“KPIs”) and industry benchmarks such as distributionsas a per cent of cash flow from operating activities, operating netbacks (“netbacks”),total capitalization, finding, development and acquisition costs, recycleratio, reserve life index, reserves per unit and production per unit to analyzefinancial and operating performance. Management feels that these KPIs andbenchmarks are key measures of profitability and overall sustainability for theTrust. These KPIs and benchmarks as presented do not have any standardizedmeaning prescribed by Canadian GAAP and therefore may not be comparable withthe calculation of similar measures for other entities.

 

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Executive Overview

 

ARC Energy Trust (“the Trust”)is one of the top 20 producers of conventional oil and gas in western Canada.In terms of oil and gas entities operating in western Canada and listed on theToronto Stock Exchange, ARC ranks 14 with a total capitalization as at February 13,2008 of $5.7 billion based on a closing unit price of $23.15.

 

It is the Trust’s objective toprovide superior and sustainable long-term returns to unitholders by focusingon the key strategic objectives of the business plan. The Trust, which to datehas conducted business exclusively in western Canada, acquires, develops andoptimizes oil and natural gas properties to generate a cash flow stream. TheTrust at December 31, 2007, held an interest in over 18,000 wells withapproximately 5,500 wells operated by the Trust and the remainder operated byjoint venture partners, primarily major oil and gas companies. ARC’s 2007production averaged 62,723 boe per day of which 74 per cent was operated by theTrust. The Trust’s business plan is to continually develop its reserves and/oracquire new reserves and undeveloped land in order to maintain or grow itsproductive capacity while distributing the remainder of its cash flows tounitholders in the form of monthly distributions. The Trust employs aconservative payout policy to provide for cash funding of a portion of ongoingcapital development programs and maintaining low debt levels to facilitatefurther growth.

 

The key objectives of the Trust’sbusiness plan are identified below. The Trust was successful in meeting all ofits objectives in 2007 as discussed below and will continue to focus on theseitems in 2008.

 

·                  Managing commodity price risk –Commodity prices are by far the key variable in determining the profitabilityof the Trust. Each $1 per barrel change in the Canadian price of oil impactsthe annual revenue of the Trust by approximately $10 million and each $0.25 permcf change in natural gas prices at AECO impacts annual revenue by $16 million.Commodity prices are outside of management’s control, however, it is astrategic objective of the Trust to maintain a balanced production profilebetween natural gas and crude oil. Also, the Trust maintains an active riskmanagement program to protect a portion of cash flow giving greater certaintyto distributions and increasing the certainty that acceptable rates of returnsare achieved on capital deployed during the course of the year.

 

·                  Replacing annual reserves – The Trust’s provedplus probable reserves were maintained after producing 22.9 mmboe during 2007.As at December 31, 2007, company interest reserves of 286.4 mmboe werewithin one per cent of the 286.1 mmboe recorded as at December 31, 2006.The reserves were slightly increased through a combination of the $397 million2007 capital development program and property acquisitions (net ofdispositions) of $42.5 million. The Trust recorded an all-in annual Finding,Development and Acquisition (“FD&A”) cost of $19.00 per barrel of oilequivalent (“boe”) in 2007 before consideration of future development capital (“FDC”)for the proved plus probable reserves category. This is a 15 per cent reductionfrom the $22.42 per boe FD&A cost realized in 2006. Including FDC, theFD&A cost was $20.03 per boe. For additional information please refer tothe reserves section.

 

·                  Ensuring acquisitions are strategic and enhance unitholderreturns – The Trust added producing properties in southeastSaskatchewan that were synergistic with the Trust’s existing operations in 2007and also significantly increased its land ownership in northeastern BritishColumbia providing an increase in its inventory of future developmentopportunities.

 

·                  Controlling costs – The Trust has beendiligent in ensuring that costs incurred for capital projects were reasonableand competitive amongst service providers, which has led to a moderate costsavings throughout 2007. The Trust drills approximately 300 wells per year thatare added to its operating base. It is expected that operating costs willcontinue to increase over time as there is a high percentage of fixed costs forthe Trust’s properties that results in a trend of increasing operating costs asnew production is brought on to replace declines on existing properties.

 

·                  Conservatively utilizing debt – TheTrust’s net debt levels were under 15 per cent of total capitalization and debtto 2007 cash flow from operating activities was less than 1.1 times for theyear ended 2007. The Trust’s debt levels are among the lowest in the oil andgas sector.

 

·                  Continuously developing the expertise of our staff andseeking to hire and retain the best in the industry – TheTrust runs an active training and development program for its employees andencourages personal development. The Trust continually assesses compensationlevels in the industry to ensure that the Trust’s compensation is competitivein order to attract and retain the best employees. The Trust’s long-termincentive plan for employees is directly tied to the Trust’s units providingalignment between employees and investors.

 

·                  Building relationships and conducting business in a way thatis viewed as fair and equitable – ARC employees, leadershipteam and directors work hard to build the ARC “franchise value” through honest,transparent dealings with our business partners. “Treating all people withrespect” is a key message inside and outside the organization. This basicbusiness fundamental allows us to build enduring relationships with jointventure partners, land owners, investors, banks and lending institutions,governments and the investment community.

 

·                  Promoting the use of proven and effective technologies – TheTrust continues to research new technologies in an effort to conduct itsoperations in the most efficient and cost effective manner. The Trust hascommitted a portion of its 2008 capital expenditure budget towards continuedresearch into tertiary recovery methods.

 

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·                  Being an industry leader in health, safety and environmentalperformance – The Trust continues to focus on operating in a safe,reliable and responsible fashion. The Trust is committed to the platinum levelof CAPP Stewardship reporting and continues to achieve Gold Level Championreporter status under the Canada Climate Change voluntary climate registryinitiative. The Trust’s commitment to pursue additional CO2injection opportunities is expected to have the two-fold benefit of enhancedrecovery of oil reserves and the capture and containment of CO2emissions that will benefit the environment. The Trust’s commitment to safetyis evidenced by zero lost time incidents for both employees and contractors ofthe Trust in 2007.

 

·                  Continuing to actively support local initiatives in thecommunities in which we live and work – The Trust is activelyinvolved in charitable and philanthropic causes both in Calgary and in therural communities in which it operates. ARC continued to be a strong supporterof the United Way, Alberta Cancer Foundation, Canadian Sport Centre Calgary,Alberta Children’s Hospital and many community organizations in rural centres.The Trust allocates up to 0.5 per cent of its three year rolling average netincome for donations, which resulted in $1.8 million of cash donations made tocharitable organizations in 2007. The Trust also provided business expertiseand employee volunteers to charities.

 

Historical Performance

 

Management and the Trust’sdirectors are committed to providing superior long-term returns to unitholders.In the future the Trust’s business strategy will continue to be reviewed toaddress changes in the business and regulatory environment in order to ensurethat unitholder value is optimized. The Trust, while primarily focused onadding value through internal development of drilling opportunities,continually looks to execute minor property acquisitions and dispositions inorder to enhance and streamline the Trust’s portfolio of oil and natural gasassets. The Trust will continue to assess larger accretive acquisitionopportunities. Acquisitions are evaluated internally and acquisitions in excessof $25 million are subject to Board approval.

 

The following table illustratesARC’s production and reserves per unit that have been achieved whiledistributing $6.79 per unit or $1.4 billion over the last three years.

 
| **Per Trust Unit**                  | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Normalized  production per unit (1) |       | 0.30     |       | 0.31     |       | 0.32     |       |
| Normalized  reserves per unit (1)   |       | 1.35     |       | 1.40     |       | 1.51     |       |
| Distributions  per unit             |       | $        | 2.40       |     | $          | 2.40     |       | $ | 1.99 |   |
|                                     |            |          |            |          |            |          |            |  |  |  |

 

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(1)          Normalized indicates that allyears as presented have been adjusted to reflect a net debt to capitalizationof 15 per cent. It is assumed that additional trust units were issued (orrepurchased) at a period end price for the reserves per unit calculation and atan annual average price for the production per unit calculation in order toachieve a net debt balance of 15 per cent of total capitalization each year.The normalized amounts are presented to enable comparability of annual per unitvalues.

 

The result of the Trust’sbusiness plan have provided unitholders with the following one, three and fiveyear returns, on the basis of reinvestment of distributions in trust units:

 

TOTAL RETURNS

 
| **($ per unit except for per cent)** | ** ** | **One Year** | ** ** | **Three  Year** | ** ** | **Five  Year** |   |
|-------------------------------------------|------------|--------------|------------|-----------------|------------|----------------|--------|
| Distributions  per unit                   |       | $            | 2.40       |            | $          | 6.79           |   | $ | 10.39 |   |
| Capital  appreciation per unit            |       | $            | (1.90      | )               | $          | 2.50           |   | $ | 8.50 |   |
| Total return  per unit                    |       | $            | 0.50       |            | $          | 9.29           |   | $ | 18.89 |   |
| Annualized  total return per unit         |       | %            | 2.3        |            | %          | 15.3           |   | % | 24.3 |   |
|                                           |            |              |            |                 |            |                |        |  |  |  |  |  |  |

 

To the end of 2007, the Trusthas provided cumulative distributions of $21.03 per unit and capitalappreciation of $10.40 per unit for a total return of $31.43 per unit (21.9 percent annualized total return) for unitholders who invested in the Trust atinception in 1996. The Trust has announced 2008 distributions of $0.20 per unitper month through March 2008.

 

Regulatory Changes

 

Beyond 2008, regulatory issuesinclude the implementation of new royalty rates for production in the Provinceof Alberta in 2009. The Alberta government announced changes in the royaltyrates in 2007 that will result in an approximate 10 per cent increase in theTrust’s royalty rates at year-end 2007 commodity prices, from approximately 18per cent of revenue to 20 per cent of revenue commencing on January 1,2009. The impact of the royalty increase was to decrease the net present valueof the Trust’s reserves by approximately two to three per cent when using a 10per cent discount rate and GLJ forecast prices as at January 1, 2008. Athigher prices, the impact would be greater.

 

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Further, the Trust will besubject to a Federal income tax on distributions commencing on January 1,2011. The Trust’s management is reviewing the options for structural changesand is working closely with legal and business advisors to determine a courseof action and potential restructuring to maximize value in the best interest ofunitholders.

 

2007 Annual Financial andOperational Results

 

Following is a discussion ofARC’s 2007 annual financial and operating results.

 

FINANCIAL HIGHLIGHTS

 
| **(CDN $ millions, except per  unit and volume data)**         | ** ** | **2007** | ** ** | **2006** | ** ** | **% Change** | ** ** |
|---------------------------------------------------------------------|------------|----------|------------|----------|------------|--------------|------------|
| Cash flow  from operating activities                                |       | 704.9    |       | 734.0    |       | (4           | )          |
| Cash flow from  operating activities per unit (1)                   |       | 3.35     |       | 3.59     |       | (7           | )          |
| Net income                                                          |       | 495.3    |       | 460.1    |       | 8            |       |
| Net income  per unit (2)                                            |       | 2.39     |       | 2.28     |       | 5            |       |
| Distributions  per unit (3)                                         |       | 2.40     |       | 2.40     |       | —       |       |
| Distributions  as a per cent of cash flow from operating activities |       | 71       |       | 66       |       | 8            |       |
| Average  daily production (boe/d) (4)                               |       | 62,723   |       | 63,056   |       | (1           | )          |

 

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| (1)    |   | Per unit amounts are based on weighted average trust units  outstanding plus trust units issuable for exchangeable shares at year-end.                                                                                                                                                                                                                                                                                                   |
|--------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| (2)    |   | Based on net income after non-controlling interest divided  by weighted average trust units outstanding excluding trust units issuable  for exchangeable shares.                                                                                                                                                                                                                                                                         |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| (3)    |   | Based on number of trust units outstanding at each cash  distribution date.                                                                                                                                                                                                                                                                                                                                                              |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| (4)    |   | Reported production amount is based on company interest  before royalty burdens. Where applicable in this MD&A natural gas has  been converted to barrels of oil equivalent (“boe”) based on 6 mcf:1 bbl. The  boe rate is based on an energy equivalent conversion method primarily  applicable at the burner tip and does not represent a value equivalent at the  well head. Use of boe in isolation may be misleading. |

 

NET INCOME

 

Net income in 2007 was $495.3million ($2.39 per unit), an increase of $35.2 million from $460.1 million($2.28 per unit) in 2006. This resulted from a $13 million gain on the sale ofthe Trust’s long-term investment as well as a significant future income taxrecovery of $121.3 million, attributed to the reduction in legislated futurecorporate income tax rates in addition to recording a future tax asset for taxlegislation commencing in 2011 related to ARC Energy Trust.

 

CASH FLOW FROM OPERATING ACTIVITIES

 

Cashflow from operating activities decreased by four per cent in 2007 to $704.9million from $734 million in 2006. The decrease in 2007 cash flow fromoperating activities is detailed in the following table.

 
| ** **                               | ** ** | **($ millions)** | ** ** | **($ per trust unit)** | ** ** | **(% variance)** | ** ** |
|------------------------------------------|------------|-----------------------|------------|-----------------------------|------------|------------------|------------|
| 2006 Cash flow from Operating Activities |       | 734.0                 |       | 3.59                        |       |             |       |
| Volume variance                          |       | (6.5                  | )          | (0.03                       | )          | (1               | )          |
| Price variance                           |       | 27.6                  |       | 0.14                        |       | 4                |       |
| Cash gains on risk management contracts  |       | (15.1                 | )          | (0.07                       | )          | (2               | )          |
| Royalties                                |       | 2.8                   |       | 0.01                        |       | —           |       |
| Expenses:                                |       |                  |       |                        |       |             |       |
| Transportation                           |       | (1.9                  | )          | (0.01                       | )          | —           |       |
| Operating (1)                            |       | (23.9                 | )          | (0.11                       | )          | (3               | )          |
| Cash G&A                             |       | (9.6                  | )          | (0.05                       | )          | (1               | )          |
| Interest                                 |       | (5.2                  | )          | (0.03                       | )          | (1               | )          |
| Taxes                                    |       | 0.4                   |       | —                      |       | —           |       |
| Realized foreign exchange gain           |       | (0.4                  | )          | —                      |       | —           |       |
| Weighted average trust units             |       | —                |       | (0.10                       | )          | —           |       |
| Non-cash and other items (2)             |       | 2.7                   |       | 0.01                        |       | —           |       |
| 2007 Cash flow from Operating Activities |       | 704.9                 |       | 3.35                        |       | (4               | )          |

 

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(1)          Excludes non-cash portionof LTIP expense recorded in operating costs.

 

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(2)          Includes the changes innon-cash working capital and expenditures on site restoration and reclamation.

 

PRODUCTION

 

Productionvolume averaged 62,723 boe per day in 2007 compared to 63,056 boe per day in2006 as detailed in the table below. Late in the fourth quarter of 2007, theTrust brought on new production in both the Dawson and Pouce areas, achievingexit production of approximately 65,000 boe per day by the end of December 2007.

 
| **Production**                             | ** ** | **2007** | ** ** | **2006** | ** ** | **% Change** | ** ** |
|--------------------------------------------|------------|----------|------------|----------|------------|--------------|------------|
| Light &  medium crude oil (bbl/d) |       | 27,366   |       | 27,674   |       | (1           | )          |
| Heavy oil  (bbl/d)                         |       | 1,316    |       | 1,368    |       | (4           | )          |
| Natural gas  (mcf/d)                       |       | 180,086  |       | 179,067  |       | 1            |       |
| NGL (bbl/d)                                |       | 4,027    |       | 4,170    |       | (3           | )          |
| Total  production (boe/d) (1)              |       | 62,723   |       | 63,056   |       | (1           | )          |
| % Natural  gas production                  |       | 48       |       | 47       |       |         |       |
| % Crude oil  and liquids production        |       | 52       |       | 53       |       |         |       |

 

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(1)          Reported production for aperiod may include minor adjustments from previous production periods.

 

Oil production decreasedslightly to 28,682 boe per day from 29,042 boe per day in 2006. Natural gasproduction was 180.1 mmcf per day in 2007, essentially unchanged from the 179.1mmcf per day produced in 2006. The stable production was a result of ARC’sactive 2007 internal drilling program particularly in northern and southeastAlberta as well as southwestern Saskatchewan. The Trust drilled six horizontalnatural gas wells in the Dawson area as well as 144 natural gas wells insoutheastern Alberta and southwestern Saskatchewan during 2007.

 

The Trust’s objective is tomaintain annual production through the drilling of wells and other developmentactivities. In fulfilling this objective, there may be fluctuations inproduction depending on the timing of new wells coming on-stream. During 2007,the Trust drilled 278 gross wells (220 net wells) on operated properties; 99gross oil wells, three water injection wells and 172 gross natural gas wellswith a 99 per cent success rate.

 

The Trust expects that 2008full year production will be approximately 63,000 boe per day and that 310gross wells (252 net wells) will be drilled by ARC on operated properties withparticipation in an additional 140 gross wells to be drilled on the Trust’snon-operated properties. The Trust estimates that the 2008 drilling programwill add sufficient production from new wells to offset production declines onexisting properties.

 

The following table summarizesthe Trust’s production by core area:

 
| ** **                     | ** ** | **2007**           | ** ** | **2006**         | ** ** |
|--------------------------------|------------|--------------------|------------|------------------|------------|
| **Production  Core Area (1)**  |       | **Total  (boe/d)** | ** ** | **Oil  (bbl/d)** | ** ** | **Gas  (mmcf/d)** | ** ** | **NGL  (bb1/d)** | ** ** | **Total  (boe/d)** | ** ** | **Oil  (bb1/d)** | ** ** | **Gas  (mmcf/d)** | ** ** | **NGL  (bb1/d)** |   |
| Central AB                     |       | 7,967              |       | 1,596            |       | 30.3 |   | 1,319 |   | 8,206 |   | 1,553 |   | 31.3 |   | 1,433 |   |
| Northern  AB & BC     |       | 19,797             |       | 5,773            |       | 74.8 |   | 1,552 |   | 18,897 |   | 6,194 |   | 67.6 |   | 1,452 |   |
| Pembina &  Redwater   |       | 13,703             |       | 9,474            |       | 19.2 |   | 1,034 |   | 13,950 |   | 9,453 |   | 20.0 |   | 1,157 |   |
| S.E.  AB & S.W. Sask. |       | 10,040             |       | 1,044            |       | 53.9 |   | 10 |   | 10,743 |   | 1,071 |   | 58.0 |   | 9 |   |
| S.E.  Sask. & MB      |       | 11,216             |       | 10,795           |       | 1.9 |   | 112 |   | 11,260 |   | 10,771 |   | 2.2 |   | 119 |   |
| Total                          |       | 62,723             |       | 28,682           |       | 180.1 |   | 4,027 |   | 63,056 |   | 29,042 |   | 179.1 |   | 4,170 |   |

 

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(1)          Provincial references: ABis Alberta, BC is British Columbia, Sask. is Saskatchewan, MB is Manitoba, S.E.is southeast and S.W. is southwest.

 

COMMODITY PRICES PRIOR TO HEDGING

 
| ** **                                      | ** ** | **2007** | ** ** | **2006** | ** ** | **% Change** | ** ** |
|-------------------------------------------------|------------|----------|------------|----------|------------|--------------|------------|
| Average  Benchmark Prices                       |       |     |       |     |       |         |       |
| AECO gas  ($/mcf) (1)                           |       | 6.61     |       | 6.98     |       | (5           | )          |
| WTI oil  (US$/bbl) (2)                          |       | 72.37    |       | 66.25    |       | 9            |       |
| US$/C$ foreign exchange rate               |       | 0.94     |       | 0.88     |       | 7            |       |
| WTI oil (CDN  $/bbl)                            |       | 77.35    |       | 75.00    |       | 3            |       |
| ARC Realized  Prices Prior to Hedging           |       |     |       |     |       |         |       |
| Oil ($/bbl)                                     |       | 69.24    |       | 65.26    |       | 6            |       |
| Natural gas  ($/mcf)                            |       | 6.75     |       | 6.97     |       | (3           | )          |
| NGL ($/bbl)                                     |       | 54.79    |       | 52.63    |       | 4            |       |
| Total  commodity revenue before hedging ($/boe) |       | 54.54    |       | 53.33    |       | 2            |       |
| Other  revenue ($/boe)                          |       | 0.13     |       | 0.13     |       | —       |       |
| Total  revenue before hedging ($/boe)           |       | 54.67    |       | 53.46    |       | 2            |       |

 

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(1)          Represents the AECOmonthly posting.

 

(2)          WTI represents West TexasIntermediate posting as denominated in US$.

 

Althoughoil prices have achieved record highs throughout 2007 peaking at US$95.58 perbarrel and averaging US$72.37 per barrel for the full year, the strengtheningof the Canadian dollar relative to the U.S. dollar was responsible for erodingmost of the gains and negatively impacted the price of oil in Canadian dollarterms. The price of oil in U.S. dollars increased by nine per cent for the fullyear of 2007, however, the Canadian dollar equivalent increased by only threeper cent. The foreign exchange rate reached record highs in 2007 with theCanadian dollar peaking at an exchange rate of 1.1030 US$/C$ in November 2007.The average US$/C$ foreign exchange rate was 0.93 US$/C$ for the full year of2007 and the Canadian dollar Bank of Canada noon day rate on December 31,2007 was 1.01 US$/C$.

 

The Trust’s oil productionconsists predominantly of light and medium crude oil while heavy oil accountsfor less than three per cent of the Trust’s liquids production. The realizedprice for the Trust’s oil, before hedging, increased six per cent to $69.24from $65.26 for the full year of 2006.

 

Alberta AECO Hub natural gasprices, which are commonly used as an industry reference, averaged $6.61 permcf in 2007 compared to $6.98 per mcf in 2006. Natural gas prices were strongerin the first half of the year but declined throughout the third and fourthquarters. ARC’s realized gas price, before hedging, decreased by three per centto $6.75 per mcf compared to $6.97 per mcf in 2006. ARC’s realized gas price isbased on prices received at the various markets in which the Trust sells itsnatural gas. ARC’s natural gas sales portfolio consists of gas sales priced atthe AECO monthly index, the AECO daily spot market, eastern and mid-west UnitedStates markets and a portion to aggregators.

 

Prior to hedging activities,ARC’s total realized commodity price was $54.67 per boe in 2007, a two per centincrease from the $53.46 per boe received prior to hedging in 2006.

 

REVENUE

 

Revenue increased to ahistorical high of $1.25 billion in 2007. The increase in revenue wasattributable to higher realized oil prices which were partially offset by lowerrealized natural gas prices as compared to 2006.

 

Abreakdown of revenue is as follows:

 
| **Revenue ($ millions)** | ** ** | **2007** | ** ** | **2006** | ** ** | **% Change** | ** ** |
|-------------------------------|------------|----------|------------|----------|------------|--------------|------------|
| Oil revenue                   |       | 724.8    |       | 691.8    |       | 5            |       |
| Natural gas  revenue          |       | 443.4    |       | 455.7    |       | (3           | )          |
| NGL revenue                   |       | 80.5     |       | 80.1     |       | —       |       |
| Total  commodity revenue      |       | 1,248.7  |       | 1,227.6  |       | 2            |       |
| Other  revenue                |       | 2.9      |       | 2.9      |       | —       |       |
| Total  revenue                |       | 1,251.6  |       | 1,230.5  |       | 2            |       |

 

RISK MANAGEMENT AND HEDGING ACTIVITIES

 

ARC continues to maintain anongoing risk management program to reduce the volatility of revenues in orderto enhance stability of distributions, protect acquisition economics, and fundcapital expenditures. The risk management program was revised in 2005 tomaintain a significant portion of upside price participation on productionvolumes that has resulted in cash hedging gains, net of premiums, of $14.1million in 2007 and $29.3 million in 2006.

 

The Trust currently limits theamount of forecast production that can be hedged to 55 per cent with the other45 per cent of production being sold for market prices.

 

During 2007, the WTI U.S.dollar posted oil price increased to a high of US$95.98 per barrel with anannual average posted price of US$72.37 per barrel. From a corporateperspective this has had a positive impact on the Trust’s revenue, however,this has resulted in a loss recorded for the Trust’s oil risk management contracts.During 2007 ARC had an unrealized total mark-to-market loss year-over-year of$55.9 million with a net unrealized mark-to-market liability of $68 million asat December 31, 2007. The mark-to-market values represent the market priceto buy-out the Trust’s contracts as of December 31, 2007 and may bedifferent from what will eventually be realized.

 

The most significant portion ofARC’s total unrealized mark-to-market position at year end was a $35.3 millionloss relating to the Redwater and NPCU hedged volumes of 5,000 bbl per day,which limits upside price potential to $85 and $90 per barrel in 2008 and 2009respectively. When these

 

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properties were acquired in2005, the acquisition economics were based on crude oil prices of approximatelyCAD$57.50 per barrel. The remainder of the mark-to-market loss results inpotential settling of commodity, foreign exchange and interest rates above thelevel of the Trust’s hedges as disclosed in Note 11 to the ConsolidatedFinancial Statements.

 

During 2007 ARC entered into anumber of hedging transactions including the following:

 

·                  Energy equivalent swap:ARC entered into an energy equivalent swap in order to shift its price exposureto be more heavily weighted towards crude oil for the period of April 1through October 31, 2008. Through the use of financial contracts, ARC hasrebalanced its price exposure from a forecasted 50:50 to a 52:48 oil-gasweighting. ARC achieved this rebalancing by selling AECO natural gas at $7.10per GJ and buying crude oil at CDN$73.95 per barrel.

 

·                  In light of thesignificant increase in value of the Canadian dollar during the last 12 months,ARC implemented a program to lock in exchange rates on future principalrepayments on U.S. dollar denominated senior secured notes. These transactionseffectively lock in the unrealized foreign exchange gains on the U.S.denominated debt. Although the unrealized foreign exchange gains will continueto fluctuate quarter-to-quarter with changes in the exchange rate, thesefinancial transactions have effectively fixed the economic gains of the changein exchange rates from the rate at which the U.S. denominated debt was issuedand the rate at which the future payments have been committed. At the end ofthe year ARC had US$218 million of U.S. denominated senior secured debtoutstanding (CDN$215.5 million) requiring annual principal repayments ofvarying amounts extending until December 15, 2017. As at December 31,2007, ARC had locked in the foreign exchange rate for a total of US$127.2million of its principal repayments in years 2012 through 2017 at an averagerate with the Canadian dollar slightly greater than par (1.02 US$/C$).

 

·                  Natural gas protectionthrough to March 2009: In the fall of 2007 ARC entered into natural gascollars to protect prices as far out as March 2009. For the period from November 2008to March 2009, ARC has purchased NYMEX natural gas puts at $8.50 per mmbtuand sold calls at $11.00 per mmbtu.

 

The percentage of forecastvolumes hedged in 2008 is: 43 per cent in the first quarter, 36 per cent in thesecond quarter, 26 per cent in the third quarter and 23 per cent in the fourthquarter.

 

The following table is anindicative summary of the Trust’s positions for crude oil, natural gas andrelated foreign exchange for the next twelve months as at December 31,2007.

 

Hedge Positions

 
| **As at December 31, 2007  (1)(2)** | ** ** | **Q1 2008** | ** ** | **Q2 2008**  | ** ** | **Q3 2008** | ** ** | **Q4 2008**  | ** ** |
|------------------------------------------|------------|-------------|------------|--------------|------------|-------------|------------|--------------|------------|
| **Crude Oil**                            | ** ** | **US$/bbl** | ** ** | **bbl/day**  | ** ** | **US$/bbl** | ** ** | **bbl/day**  | ** ** | **US$/bbl** | ** ** | **bbl/day** | ** ** | **US$/bbl** | ** ** | **bbl/day** |   |
| Sold Call                                |       | 94.08       |       | 19,000       |       | 89.04       |       | 13,000       |       | 90.00 |   | 10,000 |   | 90.00 |   | 10,000 |   |
| Bought Put                               |       | 75.14       |       | 20,000       |       | 70.47       |       | 15,500       |       | 68.13 |   | 10,000 |   | 68.13 |   | 10,000 |   |
| Sold Put                                 |       | 54.91       |       | 11,500       |       | 54.96       |       | 11,500       |       | 51.07 |   | 7,000 |   | 51.07 |   | 7,000 |   |
|                                     |       |        |       |         |       |        |       |         |       |   |   |   |   |   |   |   |   |
| **Natural Gas**                          | ** ** | **CDN$/GJ** | ** ** | **GJ/day**   | ** ** | **CDN$/GJ** | ** ** | **GJ/day**   | ** ** | **CDN$/GJ** | ** ** | **GJ/day** | ** ** | **CDN$/GJ** | ** ** | **GJ/day** | ** ** |
| Sold Call                                |       | 8.02        |       | 47,478       |       | 8.41        |       | 41,101       |       | 8.41 |   | 41,101 |   | 8.88 |   | 27,840 |   |
| Bought Put                               |       | 6.87        |       | 47,478       |       | 6.64        |       | 41,101       |       | 6.64 |   | 41,101 |   | 6.82 |   | 27,840 |   |
| Sold Put                                 |       | 4.75        |       | 10,551       |       | 4.97        |       | 31.101       |       | 4.97 |   | 31,101 |   | 5.04 |   | 10,480 |   |
|                                     |       |        |       |         |       |        |       |         |       |   |   |   |   |   |   |   |   |
| **Foreign Exchange**                     | ** ** | **C$/US$**  | ** ** | **$Million** | ** ** | **C$/US$**  | ** ** | **$Million** | ** ** | **C$/US$** | ** ** | **$Million** | ** ** | **C$/US$** | ** ** | **$Million** | ** ** |
| Bought Put                               |       | 1.0750      |       | 3.0          |       | 1.0750      |       | 3.0          |       | 1.0750 |   | 3.0 |   | 1.0750 |   | 3.0 |   |
| Sold Put                                 |       | 1.0300      |       | 3.0          |       | 1.0300      |       | 3.0          |       | 1.0300 |   | 3.0 |   | 1.0300 |   | 3.0 |   |
| Swap                                     |       | —      |       | —       |       | —      |       | —       |       | — |   | — |   | — |   | — |   |

 

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(1)          The prices and volumesnoted above represents averages for several contracts and the average price forthe portfolio of options listed above does not have the same payoff profile asthe individual option contracts. Viewing the average price of a group ofoptions is purely for indicative purposes. The natural gas price showntranslates all NYMEX positions to an AECO equivalent price. In addition topositions shown here, ARC has entered into additional basis positions.

 

(2)          Please refer to the Trust’swebsite at www.arcenergytrust.com under “Hedging Program” within the “InvestorRelations” section for details on the Trust’s hedging positions as of December 31,2007.

 

The above table should beinterpreted as follows using the first quarter 2008 Crude oil hedges as anexample. To accurately analyze the Trust’s hedge position, contracts need to bemodeled separately as using average prices and volumes may be misleading.

 

·                  If the market price isbelow $54.91, ARC will receive $75.14 less the difference between $54.91 andthe market price on 11,500 barrels per day. For example if the market price is$54.90, the Trust will receive $75.13 on 11,500 barrels per day.

 

·                  If the market price isbetween $54.91 and $75.14, ARC will receive $75.14 on 20,000 barrels per day.

 

·                  If the market price isbetween $75.14 and $94.08, ARC will receive the market price on 20,000 barrelsper day.

 

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•      Ifthe market price exceeds $94.08, ARC will receive $94.08 on 19,000 barrels perday and the market price for the remaining 1,000 hedged volumes.

 

GAIN OR LOSS ON RISK MANAGEMENT CONTRACTS

 

Gain orloss on risk management contracts comprise realized and unrealized gains orlosses on risk management contracts that do not meet the accounting definitionrequirements of an effective hedge, even though the Trust considers all riskmanagement contracts to be effective economic hedges. Accordingly, gains and losseson such contracts are shown as a separate category in the statement of income.

 

ARC realized gains on naturalgas contracts throughout the year as a result of soft prices where ARC’s floorprotection level exceeded the market price. ARC’s crude oil contracts posted aloss for the year of $5.7 million as a result of record high oil prices thatexceeded some of the Trust’s ceiling contracts during the second half of theyear. On foreign exchange and interest rates, ARC realized gains during thelast three quarters of the year particularly on U.S. dollar put-spreads thatprotected ARC from an appreciating Canadian dollar.

 

Thefollowing is a summary of the total gain (loss) on risk management contractsfor the year-over-year change as of the 2007 year-end:

 
| **Risk Management Contracts**                  | ** ** | **Crude Oil**     | ** ** | **Natural** | ** ** | **Interest &** | ** ** | **2007**  | ** ** | **2006**  | ** ** |
|------------------------------------------------|------------|-------------------|------------|-------------|------------|-------------------------|------------|-----------|------------|-----------|------------|
| **($ millions)**                          | ** ** | **& Liquids** | ** ** | **Gas**     | ** ** | **Foreign Currency**    | ** ** | **Total** | ** ** | **Total** | ** ** |
| Realized cash (loss) gain on contracts (1)     |       | (5.7              | )          | 15.4        |       | 4.4                     |       | 14.1      |       | 29.3      | ** ** |
| Unrealized (loss) gain on  contracts (2)       |       | (60.2             | )          | (2.9        | )          | 7.2                     |       | (55.9     | )          | (4.6      | )          |
| Total (loss) gain on risk management contracts |       | (65.9             | )          | 12.5        |       | 11.6                    |       | (41.8     | )          | 24.7      |       |

 

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(1)          Realized cash gains and lossesrepresent actual cash settlements or receipts under the respective contracts.

 

(2)          The unrealized (loss) gain oncontracts represents the change in fair value of the contracts during theperiod.

 

OPERATING NETBACKS

 

The Trust’s operating netback,after realized hedging gains, decreased one per cent to $35.44 per boe in 2007compared to $35.95 per boe in 2006. The decrease in netbacks in 2007 isprimarily due to a decrease in the realized gain on risk management contracts,a decrease in gas prices, as well as an increase in operating andtransportation costs. These items were partially offset by a decrease inroyalties and an increase in revenues as a result of higher oil prices in 2007.

 

The components of operatingnetbacks are shown below:

 
| ** **                                        | ** ** | **Crude Oil** | ** ** | **Heavy Oil** | ** ** | **Gas**     | ** ** | **NGL**     | ** ** | **2007 Total** | ** ** | **2006 Total** | ** ** |
|---------------------------------------------------|------------|---------------|------------|---------------|------------|-------------|------------|-------------|------------|----------------|------------|----------------|------------|
| **Netbacks ($ per boe)**                     | ** ** | **($/bbl)**   | ** ** | **($/bbl)**   | ** ** | **($/mcf)** | ** ** | **($/bbl)** | ** ** | **($/boe)**    | ** ** | **($/boe)**    | ** ** |
| Weighted average sales  price                     |       | 70.20         |       | 49.17         |       | 6.75        |       | 54.79       |       | 54.54          |       | 53.33          |       |
| Other revenue                                     |       | —        |       | —        |       | —      |       | —      |       | 0.13           |       | 0.13           |       |
| Total revenue                                     |       | 70.20         |       | 49.17         |       | 6.75        |       | 54.79       |       | 54.67          |       | 53.46          |       |
| Royalties                                         |       | (11.33        | )          | (4.34         | )          | (1.25       | )          | (14.90      | )          | (9.59          | )          | (9.66          | )          |
| Transportation                                    |       | (0.27         | )          | (1.09         | )          | (0.20       | )          | —      |       | (0.72          | )          | (0.63          | )          |
| Operating costs (1)                               |       | (11.84        | )          | (12.16        | )          | (1.26       | )          | (7.73       | )          | (9.54          | )          | (8.49          | )          |
| Netback prior to hedging                          |       | 46.76         |       | 31.58         |       | 4.04        |       | 32.16       |       | 34.82          |       | 34.68          |       |
| Realized (loss) gain on risk management contracts |       | (0.07         | )          | —        |       | 0.23        |       | —      |       | 0.62           |       | 1.27           |       |
| Netback after hedging                             |       | 46.69         |       | 31.58         |       | 4.27        |       | 32.16       |       | 35.44          |       | 35.95          |       |

 

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(1)         Operating expenses are composed of direct costs incurred tooperate oil and gas wells. A number of assumptions have been made in allocatingthese costs between oil, heavy oil, natural gas and natural gas liquidsproduction.

 

Royalties as a percentage ofpre-hedged commodity revenue net of transportation costs remained constant at18 per cent for both 2007 and 2006 at $9.59 per boe and $9.66 per boerespectively. The Trust has made a preliminary assessment of the impact of thenew Alberta Royalty legislation effective January 1, 2009 and we estimatethat the total royalties payable on the Trust’s production will increase byapproximately 10 per cent at year-end 2007 commodity prices calculated usingexpected 2009 production rates. This estimate will vary based on prices,production decline of existing wells and performance and location of new wellsdrilled. The 10 per cent increase in royalties payable which equates toapproximately a two per cent increase in the Trust’s royalty rate takes intoaccount that approximately 37 per cent of the Trust’s production is outside theProvince of Alberta. The royalty change in 2009 on a property by property basisis highly variable with decreased royalties on some properties, primarilyshallow gas wells, and a doubling of royalties on Alberta high rate oilproduction properties. The New Alberta Royalty Framework will impact futuredrilling 

 

8

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decisions in order for theTrust to maintain acceptable rates of return on its capital deployed.

 

Operating costs increased to$9.54 per boe compared to $8.49 per boe in 2006. Total operating costsincreased $23 million or, 12 per cent, in 2007. This increase was due primarilyto the additional operating costs associated with approximately 300 new wellsbrought on stream in 2007, increased labour costs for field staff and someservice providers particularly in northern operations, increased electricityconsumption and costs for well re-activations in the Redwater and NPCU areas.There are a high percentage of fixed operating costs for the Trust’s propertiesresulting in a trend of increased operating costs on a per boe basis as theproperties’ production declines over time. The Trust estimates that full year2008 operating costs will be approximately $235 million or approximately $10.20per boe based on annual production of approximately 63,000 boe per day.

 

Transportation costs increased14 per cent to $0.72 per boe in 2007 compared to $0.63 per boe in 2006 as aresult of ongoing challenges in Saskatchewan where shipping restrictions are inplace for the Enbridge pipeline. The Trust is required to truck all newproduction that exceeds our historical capacity for the Enbridge pipeline.Investors can expect transportation prices to increase again once the winterdrilling program begins and new production levels increase. An expansion of theEnbridge pipeline is expected to be completed sometime in early 2008, however,transportation costs for 2008 are still expected to increase to $0.80 per boebased on annual production of 63,000 boe per day.

 

GENERAL AND ADMINISTRATIVE EXPENSES(“G&A”) AND TRUST UNIT INCENTIVE COMPENSATION

 

G&A net of overhead recoverieson operated properties increased four per cent to $49.1 million in 2007 from$47.1 million in 2006. Increases in G&A expenses for 2007 were due toincreased staff levels, higher compensation costs and increased long-termincentive benefits. As a result of a tight labour market, the costs associatedwith hiring, compensating and retaining employees and consultants have risen.The anticipated increase in G&A costs was partially offset by higheroverhead recoveries attributed to high levels of capital and operating activitythroughout 2007 and as a result of incremental overhead charged on new andexisting operated properties.

 

The Trust paid out $12.7million under the Whole Trust Unit Incentive Plan (“Whole Unit Plan”) in 2007compared to $5.2 million in 2006 ($9.6 million and $3.5 million of the payoutswere allocated to G&A in 2007 and 2006, respectively, and the remainder tooperating costs and property, plant and equipment). The higher cash payment in2007 resulted from the Trust’s first payments for performance units issuedunder the plan in 2004. The next cash payment under the Whole Unit Plan isscheduled to occur in April 2008.

 

The following is a breakdown ofG&A and trust unit incentive compensation expense:

 

**G&A and Trust Unit Incentive CompensationExpense**
| **($ millions except per boe)**                                 | ** ** | **2007** | ** ** | **2006** | ** ** | **% Change** | ** ** |
|----------------------------------------------------------------------|------------|----------|------------|----------|------------|--------------|------------|
| G&A expenses                                                     |       | 52.7     |       | 45.8     |       | 15           |       |
| Operating recoveries                                                 |       | (16.4    | )          | (12.9    | )          | 27           |       |
| Cash G&A expenses  before Whole Unit Plan                        |       | 36.3     |       | 32.9     |       | 10           |       |
| Cash Expense – Whole Unit  Plan                                 |       | 9.6      |       | 3.5      |       | 174          |       |
| Cash G&A expenses  including Whole Unit Plan                     |       | 45.9     |       | 36.4     |       | 26           |       |
| Accrued compensation -  Rights Plan                                  |       | —   |       | 2.5      |       | (100         | )          |
| Accrued compensation -  Whole Unit Plan                              |       | 3.2      |       | 8.2      |       | (61          | )          |
| Total G&A and trust  unit incentive compensation expense         |       | 49.1     |       | 47.1     |       | 4            |       |
| Total G&A and trust  unit incentive compensation expense per boe |       | 2.15     |       | 2.05     |       | 5            |       |

 

A non-cash trust unit incentivecompensation expense (“non-cash compensation expense”) of $3.2 million ($0.14per boe) was recorded in 2007 compared to $10.7 million ($0.47 per boe) in2006. This non-cash amount relates to estimated costs of the Whole Unit Plan toDecember 31, 2007. The 2006 amounts also include estimated costs of theTrust Unit Incentive Rights Plan (“Rights Plan”) that was fully expensed at December 31,2006 with the exception of a small portion recorded in March 2007.

 

RIGHTS PLAN

 

The rights plan was replaced bya Whole Unit Plan during 2004 after which no further rights under the rightsplan were issued. The Rights Plan provided employees, officers and independentdirectors the right to purchase units at a specified price. The rights have afive year term and vest equally over three years. The exercise price of therights is adjusted downwards from time to time by the amount that distributionsto unitholders in any calendar quarter exceed 2.5 per cent of the Trust’s netbook value of property, plant and equipment. During 2007, 0.1 million rightswere exercised and 0.2 million rights remained outstanding as at December 31,2007. All of the rights have been fully expensed since March 31, 2007 and 

 

9

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are scheduled to expire on orbefore December 31, 2008.

 

WHOLE UNIT PLAN

 

In March 2004, the Boardof Directors approved a new Whole Unit Plan to replace the Rights Plan for newawards granted subsequent to the first quarter of 2004. The new Whole Unit Planresults in employees, officers and directors (the “plan participants”)receiving cash compensation in relation to the value of a specified number ofunderlying units. The Whole Unit Plan consists of Restricted Trust Units (“RTUs”)for which the number of units is fixed and will vest over a period of threeyears and Performance Trust Units (“PTUs”) for which the number of units isvariable and will vest at the end of three years.

 

Upon vesting, the planparticipant is entitled to receive a cash payment based on the fair value ofthe underlying trust units plus accrued distributions. The cash compensationissued upon vesting of the PTUs is dependent upon the performance of the Trustcompared to its peers and indicated by the performance multiplier. Theperformance multiplier is based on the percentile rank of the Trust’s totalunitholder return compared to its peers. Total return is calculated as the sumof the change in the market price of the trust units in the period plus theamount of distributions in the period. The performance multiplier ranges fromzero, if ARC’s performance ranks in the bottom quartile, to two for topquartile performance.

 

The following table shows thechanges during the year of RTUs and PTUs outstanding:

 
| **Whole Unit Plan**                                          | ** ** | **Number of** | ** ** | **Number of** | ** ** | **Total**         | ** ** |
|--------------------------------------------------------------|------------|---------------|------------|---------------|------------|-------------------|------------|
| **(units in thousands and $ millions except per unit)** | ** ** | **RTUs**      | ** ** | **PTUs**      | ** ** | **RTUs and PTUs** | ** ** |
| Balance, beginning of year                                   |       | 648           |       | 683           |       | 1,331             |       |
| Granted in the year                                          |       | 422           |       | 362           |       | 784               |       |
| Vested in the year                                           |       | (286          | )          | (110          | )          | —            |       |
| Forfeited in the year                                        |       | (38           | )          | (32           | )          | (70               | )          |
| Balance, end of year (1)                                     |       | 746           |       | 903           |       | 1,649             |       |
| Estimated distributions to  vesting date (2)                 |       | 226           |       | 350           |       | 576               |       |
| Estimated units upon  vesting after distributions            |       | 972           |       | 1,25          |       | 2,225             |       |
| Performance multiplier (3)                                   |       | —        |       | 1.7           |       | —            |       |
| Estimated total units upon  vesting                          |       | 972           |       | 1,958         |       | 2,931             |       |
| Trust unit price at  December 31, 2007                  |       | $             | 20.40      |          | $          | 20.40             |       | $ | 20.40 |   |
| Estimated total value upon  vesting                          |       | $             | 19.8       |          | $          | 39.9              |       | $ | 59.8 |   |

 

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(1)         Based on underlying units before performance multiplier andaccrued distributions.

 

(2)         Represents estimated additional units to be issued equivalentto estimated distributions accruing to vesting date.

 

(3)         The performance multiplier only applies to PTUs and wasestimated to be 1.7 at December 31, 2007 based on a weighted averagecalculation of all outstanding grants. The performance multiplier is assessedeach period end based on actual results of the Trust relative to its peers.Estimated total units upon vesting will not reconcile due to rounding.

 

The value associated with theRTUs and PTUs is expensed in the statement of income over the vesting periodwith the expense amount being determined by the unit price, the number of PTUsto be issued on vesting, and distributions. Therefore, the expense recorded inthe statement of income fluctuates over time.

 

10

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Below is asummary of the range of future expected payments under the Whole Unit Planbased on variability of the performance multiplier:

 
| **Value of Whole Unit Plan as at  December 31, 2007** | ** ** | **Performance multiplier** | ** ** |
|------------------------------------------------------------|------------|----------------------------|------------|
| **(units thousands and $ millions  except per unit)** | ** ** | **—**                 | ** ** | **1.0** | ** ** | **2.0** | ** ** |
| Estimated trust units to  vest                             |       |                       |       |   |   |   |   |
| RTUs                                                       |       | 972                        |       | 972 |   | 972 |   |
| PTUs                                                       |       | —                     |       | 1,253 |   | 2,513 |   |
| Total units (1)                                            |       | 972                        |       | 2,225 |   | 3,  485 |   |
| Trust unit price (2)                                       |       | $                          | 20.40      |   | $ | 20.40 |   | $ | 20.40 |   |
| Trust unit distributions  per month (2)                    |       | $                          | 0.20       |   | $ | 0.20 |   | $ | 0.20 |   |
| Value of Whole Unit Plan  upon vesting                     |       | 19.8                       |       | 45.4 |   | 71.1 |   |
| Officers                                                   |       | 2.1                        |       | 13.9 |   | 25.8 |   |
| Directors                                                  |       | 1.5                        |       | 1.5 |   | 1.5 |   |
| Staff                                                      |       | 16.2                       |       | 30.0 |   | 43.8 |   |
| Total payments under Whole  Unit Plan (3)                  |       | 19.8                       |       | 45.4 |   | 71.1 |   |
| 2008                                                       |       | 8.8                        |       | 16.0 |   | 23.1 |   |
| 2009                                                       |       | 6.9                        |       | 14.9 |   | 23.0 |   |
| 2010                                                       |       | 4.1                        |       | 14.5 |   | 25.0 |   |

 

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(1)         Includes additional estimated units to be issued for accrueddistributions to vesting date.

 

(2)         Values will fluctuate over the vesting period based on thevolatility of the underlying trust unit price and distribution levels. Assumesfuture trust unit price of $20.40 per trust unit and distributions of $0.20 perunit per month based on current levels.

 

(3)         Upon vesting, a cash payment is made equivalent to the valueof the underlying trust units. The payment is made on vesting dates in April andOctober of each year and at that time is reflected as a reduction of cashflow from operating activities.

 

Due to thevariability in the future payments under the plan, the Trust estimates thatbetween $19.8 million and $71.1 million will be paid out from 2008 through 2010based on the current trust unit price, distribution levels and the Trust’smarket performance relative to its peers.

 

INTEREST EXPENSE

 

Interest expense increased to$36.9 million in 2007 from $31.8 million in 2006 due to an increase inshort-term interest rates, and higher debt balances as a result of the Trust’scapital expenditure and acquisitions activity which was funded $135.7 millionwith debt. As at December 31, 2007, the Trust had $714.5 million of debtoutstanding, of which $215.5 million was fixed at a weighted average rate of5.1 per cent and $499 million was floating at current market rates plus acredit spread of 60 basis points. Fifty-two per cent of the Trust’s debt isdenominated in U.S. dollars. The cumulative decline of 1.25 per cent in theU.S. interest rates announced in January 2008 by the Federal Reserve Boardshould result in lower borrowing costs for the Trust in 2008.

 

FOREIGN EXCHANGE GAINS AND LOSSES

 

The Trust recorded a gain of$69.4 million ($3.03 per boe) on foreign exchange transactions compared to aloss of $4.2 million ($0.18 per boe) in 2006. These amounts include bothrealized and unrealized foreign exchange gains and losses.

 

Unrealized foreign exchangegains and losses are due to revaluation of U.S. denominated debt balances. Thevolatility of the Canadian dollar during the reporting period has a directimpact on the unrealized component of the foreign exchange gain or loss. Theunrealized gain/loss impacts net income but does not impact cash flow fromoperating activities as it is a non-cash amount. From December 31, 2006 toDecember 31, 2007, the US$/C$ exchange rate has increased from 0.86 to1.01 creating an unrealized gain of $64.6 million on U.S. dollar denominateddebt.

 

Realized foreign exchange gainsor losses arise from U.S. denominated transactions such as interest payments,debt repayments and hedging settlements. Included in the 2007 realized foreignexchange gain was a gain of $5 million relating, in part, to a repayment ofUS$6 million of debt in October 2007. The debt was issued in 2002 when theUS$/C$ foreign exchange rate was approximately 0.64 and strengthenedconsiderably to 1.04 on repayment in 2007.

 

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TAXES

 

In 2007, a future income taxrecovery of $121.3 million was included in income compared to an $87.1 millionrecovery in 2006. The significant increase in the future income tax recovery in2007 was due to the legislated reduction in the future corporate income taxrates in the fourth quarter of 2007 whereby the Trust’s expected futurecorporate income tax rate decreased to 25.8 per cent from the 29.4 per centprior to the rate reduction. The future income tax recovery in 2006 was alsodue to legislated reductions in the future corporate income tax rates.

 

At December 31, 2007, theTrust and the Trust’s subsidiaries had tax pools of approximately $1.84billion. The tax pools consist of $1.66 billion of tangible and intangiblecapital assets, $13.8 million of non-capital loss carry-forwards which expireat various periods to 2026, and $171.4 million of other tax pools. Included inthe above tax basis are the Trust’s tax pools of approximately $537.7 million.

 

On October 31,2006, the Finance Minister announced the Federal Government’s plan regardingthe taxation of Income Trusts. Currently, distributions paid to unitholders,other than returns of capital, are claimed as a deduction by the Trust inarriving at taxable income whereby tax is eliminated at the Trust level and ispaid by the unitholders. The Trust tax legislation that received Royal Assenton June 22, 2007, will result in a two-tiered tax structure wherebydistributions would first be subject to the federal corporate income tax rateplus a deemed 13 per cent provincial income tax at the Trust level commencingin 2011 (or earlier, if trusts that were publicly traded as of October 31,2006 exceed the normal growth guidelines announced by the Minister on December 15,2006), and then unitholders would be subject to tax on the distribution as ifit were a taxable dividend paid by a taxable Canadian corporation. As a result,the future tax position of the Trust, the parent entity, is now required to bereflected in the consolidated future income tax calculation. The Trust recordeda $35.6 million one time increase in earnings and a corresponding decrease toits future income tax liability in the second quarter as a result of timingdifferences within the Trust that had not been previously recognized. Theinitial recognition of $35.6 million comprised $24.7 million for pre-2007generated temporary differences and $10.9 million for temporary differencesrelating to the current year.

 

On October 30, 2007, theFinance Minister announced, as part of the 2007 Economic Statement, changes tothe tax system including reduction of the corporate income tax rate from 22.1per cent to 15 per cent by 2012. The reductions will be phased in between 2008and 2012. Legislation enacting the measures announced in the Economic Statementreceived Royal Assent on December 14, 2007. The reduction in the generalcorporate tax rate will also apply to the taxation of Income Trusts, reducingthe combined federal and deemed Provincial tax rate for distributions to 28 percent in 2012.

 

The Federal Government has alsoindicated that they will seek to collaborate with the provinces and territoriesto reach a combined federal-provincial-territorial statutory corporate incometax rate of 25 per cent, reflecting a 10 per cent provincial rate, equal to thecurrent Alberta tax rate. It is uncertain whether this collaboration will alsoaffect the tax on Income Trusts by reducing the proposed deemed provincial rateof 13 per cent.

 

On December 20, 2007, theFinance Minister announced technical amendments to provide some clarificationto the Trust tax legislation. As part of the announcement the Ministerindicated that the federal government intends to provide legislation in 2008 topermit Income Trusts to convert to taxable Canadian corporations without anyundue tax consequences to investors or the Trust.

 

Management and the Board ofDirectors continue to review the impact of this tax on our business strategyand while there has not been a decision as to ARC’s future direction at thistime we are of the opinion that the conversion from a trust to a corporationmay be the most logical and tax efficient alternative for ARC unitholders. Weexpect future technical interpretations and details will further clarify thelegislation. At the present time, ARC believes that if structural or othersimilar changes are not made, the after-tax distribution amount in 2011 totaxable Canadian investors will remain approximately the same, however, willdecline for both tax-deferred Canadian investors (RRSPs, RRIFs, pension plans,etc.) and foreign investors.

 

The Trust tax rate applicableto 2007 is 34 per cent, however, the application of the Trust tax should bedeferred until 2011 as the Trust has not exceeded the normal growth guidelinesannounced by the Minister. The Trust does not anticipate that the Trusttaxation legislation guidelines, which limit the growth of the Trust up to2011, will impair the Trust’s ability to annually replace or grow reserves inthe next three years as the guidelines allow sufficient growth targets. Thecorporate income tax rate applicable to 2007 is 32.1 per cent, however theTrust and its subsidiaries did not pay any material cash income taxes forfiscal 2007. Due to the Trust’s structure, currently, both income tax andfuture tax liabilities are passed on to the unitholders by means of royaltypayments made between ARC Resources and the Trust.

 

Federal capital taxes wereeliminated effective January 1, 2006 pursuant to the Federal Governmentbudget of May 2, 2006.

 

12

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DEPLETION, DEPRECIATION AND ACCRETION OFASSET RETIREMENT OBLIGATION

 

Thedepletion, depreciation and accretion (“DD&A”) rate increased to $16.23 perboe in 2007 from $15.64 per boe in 2006. The higher DD&A rate is driven byan increase in the Trust’s property, plant and equipment (“PP&E”) value onthe Trust’s balance sheet along with an increase in the future developmentcosts and a small decrease in the proved reserves recorded in the Trust’s January 1,2008 reserve report.

 

A breakdown of the DD&Arate is a follows:

 
| **DD&A Rate ($ millions  except per boe amounts)** | ** ** | **2007** | ** ** | **2006** | ** ** | **% Change** | ** ** |
|-------------------------------------------------------------|------------|----------|------------|----------|------------|--------------|------------|
| Depletion of  oil & gas assets (1)                 |       | 360.0    |       | 348.9    |       | 3            |       |
| Accretion of asset  retirement obligation (2)               |       | 11.5     |       | 11.1     |       | 4            |       |
| Total DD&A                                              |       | 371.5    |       | 360.0    |       | 3            |       |
| DD&A rate per boe                                       |       | 16.23    |       | 15.64    |       | 4            |       |

 

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(1)         Includes depletion of the capitalized portion of the assetretirement obligation that was capitalized to the PP&E balance and is beingdepleted over the life of the reserves.

 

(2)         Represents the accretion expense on the asset retirementobligation during the year.

 

GOODWILL

 

The goodwill balance of $157.6million arose as a result of the acquisition of Star Oil and Gas in 2003. Thegoodwill balance was determined based on the excess of total consideration paidplus the future income tax liability less the fair value of the assets foraccounting purposes acquired in the transaction.

 

Accounting standards requirethat the goodwill balance be assessed for impairment at least annually or morefrequently if events or changes in circumstances indicate that the balancemight be impaired. If such impairment exists, it would be charged to income inthe period in which the impairment occurs. The Trust has determined that therewas no goodwill impairment as of December 31, 2007.

 

CAPITAL EXPENDITURES AND NET ACQUISITIONS

 

Total capital expenditures,excluding acquisitions and dispositions, totaled $397.2 million in 2007compared to $364.5 million in 2006. This amount was incurred on drilling andcompletions, geological, geophysical and facilities expenditures, andundeveloped acreage. The $77.5 million purchases of undeveloped land in 2007have increased the Trust’s land holdings to 536,232 net acres that will helpsustain the drilling opportunities of the Trust which will, if successful,provide future production and reserves.

 

In addition to capitalexpenditures on development activities, the Trust completed net propertyacquisitions of $42.5 million in 2007. The most significant propertyacquisition was the purchase of properties in southeast Saskatchewan late inthe third quarter for $24.8 million. The acquisition contributed approximately350 boe per day of incremental production to the Trust’s fourth quarterresults.

 

During the year, the Trustdrilled 278 gross wells (220 net wells) on operated properties; consisting of99 gross oil wells, three water injection wells, and 172 gross natural gaswells most of which were shallow gas wells with a success rate of 99 per cent.In addition, the Trust participated in 156 gross wells (33 net wells) drilledby other operators.

 

Proved plus probable oil andgas reserves increased slightly to 286.4 mmboe at year-end 2007 as a result ofthe Trust’s 2007 capital expenditure program and property acquisitions.

 

Over the course of 2006 and2007, the Trust has spent $762 million on capital expenditures, a portion ofwhich has funded the following activities:

 

·                  At our Dawson area inBritish Columbia, ARC spent $99 million of capital to drill, complete andtie-in 10 horizontal and 13 vertical wells. ARC also expanded its compressionfacilities and signed a long-term contract with a third party processor tofacilitate processing additional gas volumes in the area. ARC’s production grewfrom 19 mmcf per day to 45 mmcf per day over the two year period. In addition,ARC has been building for the future by spending $100 million on acquiring44,000 net acres of undeveloped land in the area.

 

·                  At our Ante Creek area,ARC has focused on a combination of infill and highly successful stepout poolextension drilling. ARC has spent $61 million on drilling, completions,tie-ins, facilities, and land purchases. ARC drilled 25 wells that resulted inpositive reserves growth and record production in the area of 5,100 boe per dayfor the month of December 2007.

 

·                  In Southeast Saskatchewanwe have spent $108 million and increased production as a result of drilling 41wells in the area including 35 new horizontal oil wells, two successfulexploration locations and one new vertical injection well.

 

13

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·                  ARC’s 2007 exitproduction at Redwater was 4,300 boe per day, which represents a 20 per centincrease over production at the time that ARC closed the Redwater acquisitionin December 2005. To achieve these results, ARC invested $20 millionfocused mainly on a combination of optimization and reactivation projects andthe drilling of infill vertical wells that were identified through seismic dataacquired in 2006.

 

·                  ARC drilled 150 wells inour Southeast Alberta and Southwest Saskatchewan area including 132 shallow gaswells and 18 new oil wells.

 

A breakdown of capitalexpenditures and net acquisitions is shown below:

 
| **Capital Expenditures ($ millions)**       | ** ** | **2007** | ** ** | **2006** | ** ** | **% Change** | ** ** |
|--------------------------------------------------|------------|----------|------------|----------|------------|--------------|------------|
| Geological and geophysical                       |       | 14.9     |       | 11.4     |       | 31           |       |
| Drilling and completions                         |       | 229.5    |       | 240.5    |       | (5           | )          |
| Plant and facilities                             |       | 72.1     |       | 77.6     |       | (7           | )          |
| Undeveloped land                                 |       | 77.5     |       | 32.4     |       | 139          |       |
| Other capital                                    |       | 3.2      |       | 2.6      |       | 23           |       |
| Total capital expenditures                       |       | 397.2    |       | 364.5    |       | 9            |       |
| Producing property  acquisitions (1)             |       | 47.1     |       | 124.0    |       | (62          | )          |
| Producing property  dispositions (1)             |       | (4.6     | )          | (8.8     | )          | 48           |       |
| Corporate acquisitions (2)                       |       | —   |       | 16.6     |       | (100         | )          |
| Total capital expenditures  and net acquisitions |       | 439.7    |       | 496.3    |       | (11          | )          |

 

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(1)         Value is net of post-closing adjustments.

 

(2)         Represents total consideration for the transactions,including fees but is prior to the related future income tax liability, assetretirement obligation and working capital assumed on acquisition.

 

Approximately 49 per cent ofthe $397.2 million capital program was financed with cash flow from operatingactivities in 2007 compared to 65 per cent in 2006. Property acquisitions werefinanced through debt and working capital.

 

Source of Funding of CapitalExpenditures and Net Acquisitions

 
| ** **                          | ** ** | **2007**        | ** ** | **2006**         | ** ** |
|-------------------------------------|------------|-----------------|------------|------------------|------------|
| ** **                          | ** ** | **Development** | ** ** | **Net**          | ** ** | **Total** | ** ** | **Development** | ** ** | **Net** | ** ** | **Total** | ** ** |
| **($ millions)**               | ** ** | **Capital**     | ** ** | **Acquisitions** | ** ** | **Expenditures** | ** ** | **Capital** | ** ** | **Acquisitions** | ** ** | **Expenditures** | ** ** |
| Expenditures                        |       | 397.2           |       | 42.5             |       | 439.7 |   | 364.5 |   | 131.8 |   | 496.3 |   |
| Per cent funded by:                 |       |            |       |             |       |   |   |   |   |   |   |   |   |
| Cash flow from operating activities |       | 49              | %          | —           |       | 44 | % | 65 | % | — |   | 48 | % |
| Proceeds from DRIP and Rights Plan  |       | 28              | %          | —           |       | 25 | % | 30 | % | — |   | 22 | % |
| Debt                                |       | 23              | %          | 100              | %          | 31 | % | 5 | % | 100 | % | 30 | % |
|                                |       | 100             | %          | 100              | %          | 100 | % | 100 | % | 100 | % | 100 | % |

 

ARC has announced a $395million capital expenditure budget for 2008 that consists of a robust drillingand development program on its diverse asset base. The 2008 capital budget isbeing deployed as a balanced drilling program of low and moderate risk wells,well tie-ins and other related costs, and the acquisition of undeveloped land.The Trust continues to focus on major properties with significant upside, withthe objective to replace production declines through internal developmentopportunities. The 2008 capital expenditure budget anticipates the drilling of252 net operated wells and the addition of new production from the capitaldevelopment program to replace declines at existing properties and develop therecently acquired land holdings in the Dawson area of British Columbia. The2008 capital budget also allows for a portion of spending to further researchand pursue Enhanced Recovery Initiatives such as CO2 injection andNGC development. Current projections of cash flows, low debt levels and astrong working capital position provide the Trust with the financialflexibility to fund the 2008 capital expenditure program.

 

LONG-TERM INVESTMENT

 

During the second quarter of2007, the Trust sold its investment in the shares of a private company that wasinvolved in the acquisition of oil sands leases. The transaction closed on June 25,2007. The Trust recorded a cash gain of $13.3 million with total proceeds of$33.3 million recorded as part of cash flow from investing activities.

 

14

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ASSET RETIREMENT OBLIGATION ANDRECLAMATION FUND

 

At December 31, 2007, theTrust has recorded an Asset Retirement Obligation (“ARO”) of $140 million($177.3 million at December 31, 2006) for future abandonment andreclamation of the Trust’s properties. The ARO decreased in 2007 as a result ofa change in management’s estimate of the timing of when costs will be incurred.The estimated ARO includes assumptions of actual costs to abandon wells orreclaim the property as well as annual inflation factors in order to calculatethe undiscounted total future liability. The undiscounted total futureliability has increased to $1.3 billion as at December 31, 2007 ascompared to $1 billion at December 31, 2006, as a significant portion ofthe costs are now projected to be incurred in years 2048 to 2058 as compared toyears 2017 to 2021 as estimated on December 31, 2006. The present valueimpact of this change in estimate resulted in a $34.4 million reduction in theARO balance at December 31, 2007.

 

Included in the December 31,2007 ARO balance is a $3.8 million increase related to development activitiesin 2007. The ARO liability was also increased by $11.5 million for accretionexpense in 2007 ($11.1 million in 2006) and was reduced by $18.2 million ($10.6million in 2006) for actual abandonment expenditures incurred in 2007.

 

As a result of the Redwateracquisition in December 2005, the Trust set up a second reclamation fund(the “Redwater Fund”) in 2006 to fund future abandonment obligations attributedsolely to the Redwater properties. The Trust makes annual contributions to theRedwater fund and may utilize the funds only for abandonment activities for theRedwater property. With the addition of the Redwater Fund, the Trust nowmaintains two reclamation funds that together held $26.1 million at December 31,2007. Future contributions for the two funds will vary over time in order toprovide for the total estimated future abandonment and reclamation costs thatare to be incurred upon abandonment of the Trust’s properties. The Trustcurrently estimates that $220 million will be contributed to the funds over thenext 50 years to provide for future abandonment and reclamation costs.

 

In total, ARC contributed $12.1million cash to its reclamation funds in 2007 ($12.1 million in 2006) andearned interest of $1.4 million ($1 million in 2006) on the fund balances. Thefund balances were reduced by $18.1 million for cash-funded abandonmentexpenditures in 2007 ($5.7 million in 2006). Under the terms of the Trust’sinvestment policy, reclamation fund investments and excess cash can only beinvested in Canadian or U.S. Government securities, investment grade corporatebonds, or investment grade short-term money market securities.

 

CAPITALIZATION, FINANCIAL RESOURCES ANDLIQUIDITY

 

A breakdown of the Trust’scapital structure is as follows as at December 31, 2007 and 2006:

 
| **Capital Structure and Liquidity**                                       | ** ** | ** ** | ** ** | ** ** | ** ** |
|---------------------------------------------------------------------------|------------|------------|------------|------------|------------|
| **($ millions except per unit and  per cent amounts)**               | ** ** | **2007**   | ** ** | **2006**   | ** ** |
| Amount drawn under  revolving credit facilities                           |       | 499.0      |       | 426.1      |       |
| Senior secured notes                                                      |       | 215.5      |       | 261.0      |       |
| Working capital deficit  excluding short-term debt (1)                    |       | 38.2       |       | 52.0       |       |
| Net debt obligations                                                      |       | 752.7      |       | 739.1      |       |
| Trust units outstanding  and issuable for exchangeable shares (thousands) |       | 213.2      |       | 207.2      |       |
| Market price per unit at  end of year                                     |       | 20.40      |       | 22.30      |       |
| Market value of trust  units and exchangeable shares                      |       | 4,349.3    |       | 4,620.0    |       |
| Total capitalization (2)                                                  |       | 5,102.0    |       | 5,359.1    |       |
| Net debt as a percentage  of total capitalization                         |       | 14.8       | %          | 13.8       | %          |
| Net debt obligations                                                      |       | 752.7      |       | 739.1      |       |
| Cash flow from operating  activities                                      |       | 704.9      |       | 734.0      |       |
| Net debt to cash flow from  operating activities                          |       | 1.1        |       | 1.0        |       |

 

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(1)         The working capital deficit excludes the balances for thecurrent portion of risk management contracts and the current portion of futureincome taxes.

 

(2)         Total capitalization as presented does not have anystandardized meaning prescribed by Canadian GAAP and therefore it may not becomparable with the calculation of similar measures for other entities. Totalcapitalization is not intended to represent the total funds from equity anddebt received by the Trust.

 

15

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The Trust has a syndicatedthree year revolving credit facility allowing for maximum borrowing of up to$800 million. The debt is secured by all the Trust’s oil and gas properties andhas the following major covenants:

 
| **COVENANT**                                                                                                                                                                        | ** ** | **POSITION AS AT DECEMBER 31, 2007**                                                                                                                     |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------|
| Long-term debt and letters of  credit not to exceed three times annualized net income before non-cash  expense                                                                      |       | Long-term debt and letters of  credit of 0.9 times annualized net income before non-cash items and interest  items and interest expense                  |
|                                                                                                                                                                                |       |                                                                                                                                                     |
| Long-term debt, letters of  credit and subordinated debt not to exceed four times annualized net income  before non-cash items and interest expense                                 |       | Long-term debt, letters of  credit and subordinated debt of 0.9 times annualized net income before  non-cash items and interest expenses                 |
|                                                                                                                                                                                |       |                                                                                                                                                     |
| Long-term debt and letters of  credit not to exceed 50 per cent of the sum of the book value of unitholders’  equity, long-term debt, letters of credit, and subordinated debt |       | Long-term debt and letters of  credit of 26.5 per cent of the sum of unitholders’ equity, long-term debt, letters  of credit, and subordinated debt |

 

As indicated by the abovetable, the Trust is not close to breaching any of its covenants and hasadditional potential borrowing capacity above the $800 million credit facility.The Trust’s objective is to limit debt to under 2.0 times cash flow fromoperating activities and 20 per cent of total capitalization. In addition tothe $800 million credit facility, the Trust has outstanding senior securednotes in the amount of $215.5 million as at December 31, 2007, which donot reduce the available borrowings under the credit facility. The Trust had$4.8 million of letters of credit outstanding at December 31, 2007 and nosubordinated debt. As at December 31, 2007, the Trust was in compliancewith all covenants.

 

During the third quarter theTrust entered into treasury lock contracts in order to manage its interest rateexposure on future debt issuances. Treasury locks enable the Trust tosynthetically secure current market rates for a future fixed rate funding.These instruments hedge only the underlying treasury yield and not the creditspread applicable to ARC that is determined at the time of issuance. Based onthe transactions completed during the quarter the Trust has locked in aneffective U.S. ten year treasury rate of 4.8082 per cent on a notional amountof US$125 million. As at December 31, 2007 the mark-to-market value ofthese contracts was CDN$7.4 million loss.

 

The Trust intends to financeits $395 million 2008 capital program with cash flow from operating activitiesand the proceeds of the DRIP with any remainder financed with debt. Ifnecessary, ARC has access to additional capital through its current creditfacility, a new issue of senior secured notes, or by issuing equity. In theevent that the Trust enters into a material acquisition where the purchaseprice exceeds 10 per cent of the book value of the Trust’s assets, the ratiosin the first two covenants above are increased to 3.5 and 5.5 times, respectively.

 

UNITHOLDERS’ EQUITY

 

At December 31, 2007,there were 213.2 million trust units issued and issuable for exchangeableshares, an increase of six million trust units from December 31, 2006. Theincrease in number of trust units outstanding is mainly attributable to the 5.6million trust units issued pursuant to the DRIP during 2007 at an average priceof $19.93 per unit.

 

The Trust had 0.2 millionrights outstanding as of December 31, 2007 under an employee plan wherefurther rights issuances were discontinued in 2004. The rights have a five-yearterm and vested equally over three years from the date of grant. The remainingrights may be exercised to purchase trust units at an average adjusted exerciseprice of $8.50 per unit as at December 31, 2007. All of the rights werefully vested at December 31, 2007 and will expire on or before December 31,2008.

 

The Whole Unit Plan introducedin 2004 is a cash compensation plan for employees, officers and directors ofthe Trust and does not involve any units being issued from treasury. The Trusthas made provisions whereby employees may elect to have units purchased forthem on the market with the cash received upon vesting.

 

Unitholders electing toreinvest distributions or make optional cash payments to acquire trust unitsfrom treasury under the DRIP may do so at a five per cent discount to theprevailing market price with no additional fees or commissions. During 2007,the Trust raised proceeds of $110.7 million and issued 5.6 million trust unitspursuant to the DRIP.

 

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DISTRIBUTIONS

 

ARC declared distributions of$498 million ($2.40 per unit), representing 71 per cent of 2007 cash flow fromoperating activities compared to distributions of $484.2 million ($2.40 perunit), representing 66 per cent of cash flow from operating activities in 2006.

 

Monthly distributions for 2007were $0.20 per unit. Revisions, if any, to the monthly distribution arenormally announced on a quarterly basis in the context of prevailing andanticipated commodity prices at that time.

 

The following items may bededucted from cash flow from operating activities to arrive at distributions tounitholders:

 

·                  The portion of capitalexpenditures that are funded with cash flow from operating activities. In 2007,the Trust withheld 27 per cent of 2007 cash flow from operating activities tofund 49 per cent of the capital program excluding acquisitions. The remainingportion of capital expenditures was financed by proceeds from the DRIP programand debt.

 

·                  An annual contribution tothe reclamation funds, with $13.5 million being contributed in 2007 includinginterest earned on the fund balances. The reclamation funds are segregated bankaccounts or subsidiary trusts and the balances will be drawn on in futureperiods as the Trust incurs abandonment and reclamation costs over the life ofits properties.

 

·                  Debt principal repaymentsfrom time to time as determined by the board of directors. The Trust’s currentdebt level is well within the covenants specified in the debt agreements and,accordingly, there are no current mandatory requirements for repayment. Referto the “Capital Structure and Liquidity” section of this MD&A for adetailed review of the debt covenants.

 

·                  Income taxes that are notpassed on to unitholders. The Trust has a liability for future income taxes dueto the excess of book value over the tax basis of the assets of the Trust andits corporate subsidiaries. The Trust currently, and up until January 1,2011, may minimize or eliminate cash income taxes in corporate subsidiaries bymaximizing deductions, however in future periods there may be cash income taxesif deductions are not sufficient to eliminate taxable income. Taxability of theTrust is currently passed on to unitholders in the form of taxabledistributions whereby corporate income taxes are eliminated at the Trust level.The Trust taxation legislation, which will take effect in 2011, will result intaxes payable at the Trust level and therefore distributions to unitholderswill decrease.

 

·                  Working capitalrequirements as determined by the board of directors. Certain working capitalamounts may be deducted from cash flow from operating activities, however suchamounts would be minimal and the Trust does not anticipate any such deductionsin the foreseeable future.

 

·                  The Trust has certainobligations for future payments relative to employee long-term incentivecompensation. Presently, the Trust estimates that $19.8 million to $71.1million will be paid out pursuant to such commitments in 2008 through 2010subject to vesting provisions and future performance of the Trust. Theseamounts will reduce cash flow from operating activities and may in turn reducedistributions in future periods.

 

Cash flow from operatingactivities and distributions in total and per unit were as follows:

 
| **Cash Flow From Operating Activities**           | ** ** | ** **            | ** ** | ** ** | ** ** | ** **                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** **        | ** ** |
|-----------------------------------------------------------------------|------------|-----------------------|------------|------------|------------|----------------------------|------------|------------|------------|------------|------------|-------------------|------------|
| **and Distributions**                                            | ** ** | **2007**              | ** ** | **2006**   | ** ** | **% Change**          | ** ** | **2007**   | ** ** | **2006**   | ** ** | **% Change** | ** ** |
| ** **                                                            | ** ** | **($ millions)** | ** ** | ** ** | ** ** | **($ per unit)** | ** ** | ** ** | ** ** |
| Cash flow from operating activities                                   |       | 704.9                 |       | 734.0      |       | (4                         | )          | 3.35       |       | 3.59       |       | (7                | )          |
| Reclamation fund contributions (1)                                    |       | (13.5                 | )          | (13.1      | )          | 3                          |       | (0.06      | )          | (0.06      | )          | —            |       |
| Capital expenditures funded with cash flow from  operating activities |       | (193.4                | )          | (236.7     | )          | (18                        | )          | (0.92      | )          | (1.16      | )          | (21               | )          |
| Other (2)                                                             |       | —                |       | —     |       | —                     |       | 0.03       |       | 0.03       |       | —            |       |
| Distributions                                                         |       | 498.0                 |       | 484.2      |       | 3                          |       | 2.40       |       | 2.40       |       | —            |       |

 

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| (1)    | Includes interest income earned on the reclamation fund  balances that is retained in the reclamation funds.                                                                                                                                                                                                                                                                                                                         |
|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                 |
| (2)    | Other represents the difference due to distributions paid  being based on actual trust units outstanding at each distribution date  whereas per unit cash flow from operating activities, reclamation fund  contributions and capital expenditures funded with cash flow from operated  activities are based on weighted average outstanding trust units in the year  plus trust units issuable for exchangeable shares at year-end. |

 

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The Trust continually assessesdistribution levels, in light of commodity prices and production volumes, toensure that distributions are in line with the long-term strategy andobjectives of the Trust as per the following guidelines:

 

·                  To maintain a level ofdistributions that, in the opinion of Management and the Board of Directors, issustainable for a minimum period of six months. The Trust’s objective is tonormalize the effect of volatility of commodity prices rather than to pass onthat volatility to unitholders in the form of fluctuating monthlydistributions.

 

·                  To ensure that the Trust’sfinancial flexibility is maintained by a review of the Trust’s debt to equityand debt to cash flow from operating activities levels. The use of cash flowfrom operating activities to fund capital development activities reduces therequirements of the Trust to use debt to finance these expenditures. In 2007the Trust funded 49 per cent of capital development activities with 27 per centof cash flow from operating activities. The actual amount of cash flowswithheld to fund the Trust’s capital expenditure program is dependent on thecommodity price environment and is at the discretion of the Board of Directors.

 

The actual amount of futuremonthly distributions is proposed by management and is subject to the approvaland discretion of the Board of Directors. The Board reviews future distributionsin conjunction with their review of quarterly financial and operating results.

 

Monthly distributions for thefirst quarter of 2008 have been set at $0.20 per unit subject to monthly reviewbased on commodity price fluctuations. Revisions, if any, to the monthlydistribution are normally announced on a quarterly basis in the context ofprevailing and anticipated commodity prices at that time.

 

HISTORICAL DISTRIBUTIONS BY CALENDAR YEAR

 

Thefollowing table presents distributions paid and payable for each calendarperiod.

 
| **Calendar Year** | ** ** | **Distributions** | ** ** | **Taxable Portion** | ** ** | **Return of Capital** | ** ** |
|------------------------|------------|-------------------|------------|--------------------------|------------|---------------------------------|------------|
| 2008 YTD (1)           |       | 0.20              |       | 0.20                     |       | 0.00                            |       |
| 2007                   |       | 2.40              |       | 2.32                     |       | 0.08                            |       |
| 2006 (2)               |       | 2.60              |       | 2.55                     |       | 0.05                            |       |
| 2005                   |       | 1.94              |       | 1.90                     |       | 0.04                            |       |
| 2004                   |       | 1.80              |       | 1.69                     |       | 0.11                            |       |
| 2003                   |       | 1.78              |       | 1.51                     |       | 0.27                            |       |
| 2002                   |       | 1.58              |       | 1.07                     |       | 0.51                            |       |
| 2001                   |       | 2.41              |       | 1.64                     |       | 0.77                            |       |
| 2000                   |       | 1.86              |       | 0.84                     |       | 1.02                            |       |
| 1999                   |       | 1.25              |       | 0.26                     |       | 0.99                            |       |
| 1998                   |       | 1.20              |       | 0.12                     |       | 1.08                            |       |
| 1997                   |       | 1.40              |       | 0.31                     |       | 1.09                            |       |
| 1996                   |       | 0.81              |       | —                   |       | 0.81                            |       |
| Cumulative             |       | $                 | 21.23      |                     | $          | 14.41                           |       | $ | 6.82 |   |
|                        |            |                   |            |                          |            |                                 |            |  |  |  |

 

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| (1)    | Based on distributions declared at January 31, 2008  and estimated taxable portion of 2008 distributions of 98 per cent. |
|--------|-------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                          |
| (2)    | Based on distributions paid and payable in 2006.                                                                              |

 

Pleaserefer to the Trust’s website at www.arcenergytrust.com for details on 2007 monthlydistributions and distribution dates for 2008.

 

TAXATION OF DISTRIBUTIONS

 

Distributions comprise a returnof capital portion (tax deferred) and a return on capital portion (taxable).The return of capital component reduces the cost basis of the trust units held.For 2007, distributions paid in the calendar year will be 97 per cent return oncapital or $2.32 per unit for the year (taxable) and three per cent return ofcapital or $0.08 per unit for the year (tax deferred). For a more detailedbreakdown, please visit our website at www.arcenergytrust.com.

 

PER UNIT RESULTS AND SUSTAINABILITY

 

Due to natural productiondeclines, the Trust must continually develop its reserves and/or acquire newreserves in an effort to maintain reserves, production and cash flow levels onwhich distributions are paid. The Trust facilitates this by withholding aportion of cash flow from operating activities to fund a portion of ongoingcapital development activities and maintain moderate debt levels; this isevidenced by the Trust’s moderate 

 

18

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payout of distributions ascompared to cash flow from operating activity levels. Oil and gas royaltytrusts hold assets that are depleting and unitholders should expect production,revenue, cash flows and distributions to decline over the long-term if reservescannot be economically replaced. The Trust has an inventory of internaldevelopment prospects that we expect will enable the Trust to maintainproduction for a minimum period of two years. The Trust measures itssustainability and success in terms of per unit distributions, production,reserves, and cash flow from operating activities in addition to the ability tomaintain low debt levels and the annual replacement of reserves.

 

Following is a summary of thehistorical debt-adjusted production and reserves per unit and reserve lifeindex (“RLI”) on which the Trust assesses performance and sustainability:

 
| **Per Trust Unit Ratios**                            | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** | **3 Year Total** | ** ** |
|---------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------------------------|------------|
| Production per unit (1):                                            |       |     |       |     |       |     |       |                       |       |
| Unadjusted                                                          |       | 0.30     |       | 0.31     |       | 0.29     |       | —                     |       |
| Debt-adjusted (3)                                                   |       | 0.26     |       | 0.27     |       | 0.26     |       | —                     |       |
| Normalized (4)                                                      |       | 0.30     |       | 0.31     |       | 0.32     |       | —                     |       |
| Reserves per unit (2):                                              |       |     |       |     |       |     |       |                       |       |
| Unadjusted                                                          |       | 1.34     |       | 1.38     |       | 1.42     |       | —                     |       |
| Debt-adjusted (3)                                                   |       | 1.15     |       | 1.19     |       | 1.28     |       | —                     |       |
| Normalized (4)                                                      |       | 1.35     |       | 1.40     |       | 1.51     |       | —                     |       |
| Reserve life index (5)                                              |       | 12.5     |       | 12.4     |       | 12.9     |       | —                     |       |
| Cash flow from operating activities per  unit                       |       | $        | 3.35       |     | $          | 3.59     |       | $                          | 3.23       |   | $ | 10.17 |   |
| Distributions per unit                                              |       | $        | 2.40       |     | $          | 2.40     |       | $                          | 1.99       |   | $ | 6.79 |   |
| Distributions as a per cent of cash flow from  operating activities |       | 71       |       | 66       |       | 61       |       | 66                         |       |
| Per cent of cash flow from operating  activities retained           |       | 29       |       | 34       |       | 39       |       | 34                         |       |

 

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| (1)    | Represents daily average production per thousand units.  Calculated based on annual daily average production divided by weighted  average trust units outstanding including trust units issuable for  exchangeable shares.                                                                                                                                                                                                                                                                                                   |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| (2)    | Calculated based on proved plus probable reserves divided  by period end trust units outstanding including trust units issuable for  exchangeable shares.                                                                                                                                                                                                                                                                                                                                                                    |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| (3)    | Debt-adjusted indicates that all years as presented have  been adjusted to reflect a nil net debt to capitalization. It is assumed that  additional trust units were issued at a period end price for the reserves per  unit calculation and at an annual average price for the production per unit  calculation in order to reduce the net debt balance to zero in each year. The  debt-adjusted amounts are presented to enable comparability of annual per  unit values.                                                  |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| (4)    | Normalized indicates that all years as presented have been  adjusted to reflect a net debt to capitalization of 15 per cent. It is  assumed that additional trust units were issued (or repurchased) at a period  end price for the reserves per unit calculation and at an annual average  price for the production per unit calculation in order to achieve a net debt  balance of 15 per cent of total capitalization each year. The normalized  amounts are presented to enable comparability of annual per unit values. |
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |
| (5)    | Calculated based on proved plus probable reserves divided  by annual 2008 production estimate of 63,000 boe per day for 2007 RLI.                                                                                                                                                                                                                                                                                                                                                                                            |

 

During the 2005 to 2007 timeperiod the Trust’s normalized production per unit has decreased only slightlyfrom 0.32 to 0.30 boe of daily average production per thousand trust units.Normalized reserves per unit have decreased just over 10 per cent during thistime to 1.35 from 1.51 boe of proved plus probable reserves per trust unit.These levels of production and reserves per unit occurred even with the payoutof $1.4 billion of distributions ($6.79 per trust unit and 66 per cent of cashflow from operating activities) during the 2005 through 2007 time period. Thisindicates that the Trust has grown production levels to help offset natural productiondeclines and developed its reserve base. The normalized production per unit isa key measure as it indicates the ability to generate cash flows from coreoperations that in turn impacts the level of cash that may be distributed tounitholders. The Trust expects to replace production in 2008 from internaldevelopment opportunities.

 

To comparethe Trust’s results with oil and gas companies that retain all of their cashflow from operating activities to grow production and reserves, the Trust looksat normalized and distribution-adjusted production and reserves per unit whichcalculates the total reserves and production per initial investment with theassumption that distributions are reinvested through the DRIP plan.Consequently, the reserves and production per initial investment increase overtime as the investor’s number of trust units increase with distributionreinvestment. The Trust’s normalized daily average production per initialinvestment has increased from 0.35 boe per thousand trust units in 2005 to 0.40in 2007, while normalized reserves per initial investment have increased from1.66 boe at January 1, 2005 to 1.82 boe at December 31, 2007. Basedon the assumption of re-investment of the distributions for additional trustunits, one trust unit purchased on January 1, 2005 would have grown to1.35 trust units on December 31, 2007. A unitholder can replicate this byparticipating in the DRIP so that the number of units they own increases overtime.

 

The Trust’s reserve life indexdecreased slightly to 12.5 years in 2007 from 12.9 years in 2005. The RLI is ameasure of the remaining average life of the reserves based on a currentproduction estimate for 2008 of 63,000 boe per day. The Trust’s high RLI isindicative of the high quality of assets and the relatively low productiondecline rate of the properties. The acquisition of the Redwater and NPCUproperties in 2005 resulted in an increase in the RLI due to the long reservelife of the properties. In addition, the Trust has been able to replacereserves through the drill bit throughout 2006 and 2007 as no significantacquisitions have been completed during that time and yet the Trust producedalmost 46 million barrels of oil equivalent during those two years. A high RLIis key for a royalty trust as it indicates the potential sustainability ofproduction levels and cash flows over a longer period of time.

 

19

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The Trust’s distribution policycentres around the goal of providing a consistent and sustainable level ofdistributions to unitholders and to provide for future growth. The Trust hasmaintained distributions at $0.20 per unit per month since October 2005.This consistent level of distributions has allowed the Trust to finance $193.4million of capital expenditures through cash flow from operating activities in2007. In addition, low natural gas prices and high Canadian dollar valuesobserved in 2007, which negatively impacted the Trust’s cash flow fromoperating activities, did not cause the Trust to cut distributions — this wasan anomaly amongst the Trust’s peers. The Trust’s distribution as a per cent ofcash flow from operating activities for 2007 was 71 per cent. The moderatelevel of distributions is indicative of the Trust’s commitment to fund ongoingdevelopment activities with cash flow from operating activities to enablelong-term sustainability.

 

An additional measure ofsustainability is the comparison of net income to distributions. Net incomeincorporates all costs including depletion expense and other non-cash expenseswhereas cash flow from operating activities measures the cash generated in agiven period before the cost of the associated reserves. Therefore, net incomemay be more representative of the profitability of the entity and thus arelevant measure against which to measure distributions to illustratesustainability. As net income is sensitive to fluctuations in commodity prices,it is expected that there will be deviations between annual net income anddistributions. The following table illustrates the annual shortfall ofdistributions to net income as a measure of long-term sustainability.

 
| **Net Income and Distributions**                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Trailing**     | ** ** |
|---------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------------|------------|
| **($ millions except per cent)**                | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** | **3 years** | ** ** |
| Net income                                                          |       | 495.3      |       | 460.1      |       | 356.9      |       | 1,312.3          |       |
| Distributions                                                       |       | 498.0      |       | 484.2      |       | 376.6      |       | 1,358.8          |       |
| Shortfall                                                           |       | (2.7       | )          | (24.1      | )          | (19.7      | )          | (46.5            | )          |
| Shortfall as per cent of net income                                 |       | (1         | )%         | (5         | )%         | (6         | )%         | (4               | )%         |
| Distributions as a per cent of cash flow  from operating activities |       | 71         | %          | 66         | %          | 61         | %          | 66               | %          |

 

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

 

The Trust has contractualobligations in the normal course of operations including purchase of assets andservices, operating agreements, transportation commitments, sales commitments,royalty obligations, and lease rental obligations and employee agreements.These obligations are of a recurring and consistent nature and impact the Trust’scash flows in an ongoing manner. The Trust also has contractual obligations andcommitments that are of a less routine nature as disclosed in the followingtable.

 
| **Commitments**                       | ** ** | ** ** | ** ** | **Payments Due By Period** | ** ** | ** **    | ** ** | ** **     | ** ** |
|---------------------------------------|------------|------------|------------|-------------------------------------------|------------|---------------|------------|----------------|------------|
| **($ millions)**                 | ** ** | **2008**   | ** ** | **2009 – 2010**                      | ** ** | **2011-2012** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| Debt repayments (1)                   |       | 5.9        |       | 540.8                                     |       | 51.5          |       | 116.3          |       | 714.5 |   |
| Interest payments (2)                 |       | 11.0       |       | 20.2                                      |       | 15.5          |       | 13.7           |       | 60.4 |   |
| Reclamation fund contributions (3)    |       | 5.8        |       | 10.2                                      |       | 8.9           |       | 71.9           |       | 96.8 |   |
| Purchase commitments                  |       | 10.1       |       | 4.1                                       |       | 4.0           |       | 6.0            |       | 24.2 |   |
| Operating leases (4)                  |       | 6.2        |       | 8.9                                       |       | 12.4          |       | 88.1           |       | 115.6 |   |
| Risk management contract premiums (5) |       | 13.2       |       | 2.3                                       |       | —        |       | —         |       | 15.5 |   |
| Total contractual obligations         |       | 52.2       |       | 586.5                                     |       | 92.3          |       | 296.0          |       | 1,027.0 |   |

 

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| (1)    | Long-term and short-term debt, excluding interest. In the  event that the credit facility is not extended at any time before the  maturity date, the loan balance will become payable on the maturity date  which is April 15, 2010. |
|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                      |
| (2)    | Fixed interest payments on senior secured notes.                                                                                                                                                                                          |
|   |                                                                                                                                                                                                                                      |
| (3)    | Contribution commitments to a restricted reclamation fund  associated with the Redwater property acquired in 2005.                                                                                                                        |
|   |                                                                                                                                                                                                                                      |
| (4)    | Available option expiring February 2008 to reduce  office lease commitment.                                                                                                                                                          |
|   |                                                                                                                                                                                                                                      |
| (5)    | Fixed premiums to be paid in future periods on certain risk  management contracts.                                                                                                                                                        |

 

The above noted risk managementcontract premiums are part of the Trust’s commitments related to its riskmanagement program. In addition to the above premiums, the Trust hascommitments related to its risk management program. As the premiums are part ofthe underlying risk management contract, they have been recorded at fair marketvalue at December 31, 2007 on the balance sheet as part of risk managementcontracts.

 

The Trust enters intocommitments for capital expenditures in advance of the expenditures being made.At a given point in time, it is estimated that the Trust has committed tocapital expenditures equal to approximately one quarter of its capital budgetby means of giving the necessary authorizations to incur the capital in afuture period. The Trust’s 2008 capital budget has been approved by the Boardat $395 million. This commitment has not been disclosed in the commitment tableas it is of a routine nature and is part of normal course of operations foractive oil and gas companies and trusts.

 

20

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The above noted operatingleases include amounts for the Trust’s head office lease. The current leaseexpires in May 2010. In December 2007, the Trust entered into a 13year lease commitment beginning in 2010 for office space in a new building thatis under construction in downtown Calgary. The new lease commitment isreflected in the table above.

 

The Trust is involved inlitigation and claims arising in the normal course of operations. Management isof the opinion that pending litigation will not have a material adverse impacton the Trust’s financial position or results of operations and therefore thecommitment table does not include any commitments for outstanding litigationand claims.

 

The Trust has certain salescontracts with aggregators whereby the price received by the Trust is dependentupon the contracts entered into by the aggregator. This commitment has not beendisclosed in the commitment table as it is of a routine nature and is part ofnormal course of operations.

 

OFF BALANCE SHEET ARRANGEMENTS

 

The Trust has certain leaseagreements, all of which are reflected in the Contractual Obligations andCommitments table above, which were entered into in the normal course ofoperations. All leases have been treated as operating leases whereby the leasepayments are included in operating expenses or G&A expenses depending onthe nature of the lease. No asset or liability value has been assigned to theseleases in the balance sheet as of December 31, 2007.

 

FOURTH QUARTER FINANCIAL AND OPERATIONALRESULTS

 

The Trust had an active fourthquarter with $139.3 million spent on capital development activities thatcontributed to quarterly average production of 63,989 boe per day. The Trustdistributions were 72 per cent of cash flow from operating activities. Theremaining 28 per cent was used to fund $44.5 million of the fourth quartercapital development program and make contributions to the reclamation fund. Thefourth quarter was an active one for the Trust with the drilling of 77 grosswells on operated properties and new production coming on-stream in the Dawsonarea of British Columbia.

 

·                  The Trust’s fourthquarter production was 63,989 boe per day, a slight increase from the fourthquarter of 2006 where production was 63,663. As compared to the third quarterof 2007, the Trust’s production increased five per cent or 2,881 boe per day.This was primarily as a result of approximately 350 boe per day from anacquisition that the Trust completed late in the third quarter of 2007 as wellas new production in the Dawson area of British Columbia of approximately 1,400boe per day.

 

·                  The Trust spent $139.3million on capital development activities and undeveloped land in the fourthquarter compared to $121.9 million in 2006. The Trust had a very active fourthquarter with the drilling of 77 gross wells (69 net wells) on operated propertieswith a 100 per cent success rate. The Trust expanded its inventory ofundeveloped land acreage with the purchase of $42.6 million of land in thefourth quarter. The land acquired was in core areas where the Trust hasidentified strategic development opportunities.

 

·                  The fourth quarternetback before hedging increased 17 per cent to $36.63 per boe as compared to$31.37 for the same period of 2006. Record high oil prices, offset by increasedroyalties, operating costs and lower gas prices contributed to the high netbackrecorded for the quarter.

 

·                  Cash G&A expenses inthe fourth quarter increased to $1.96 per boe as compared to $1.74 for the sameperiod in 2006. The majority of the increase is attributable to a larger wholeunit plan payment made in October of 2007.

 

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FOURTH QUARTER FINANCIAL AND OPERATIONALHIGHLIGHTS

 
| **(CDN$ millions except per unit and per cent)** | ** ** | **Q4 2007** | ** ** | **Q4 2006** | ** ** | **% Change** | ** ** |
|-------------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|-------------------|------------|
| Production (boe/d)                                                                  |       | 63,989           |       | 63,663           |       | 1                 |       |
| Cash flow from operating activities                                                 |       | 173.7            |       | 159.3            |       | 9                 |       |
| Per unit                                                                            |       | $                | 0.82       |             | $          | 0.77              |       | (6 | ) |
| Distributions                                                                       |       | 125.8            |       | 122.3            |       | 3                 |       |
| Per unit                                                                            |       | $                | 0.60       |             | $          | 0.60              |       | — |   |
| Per cent of cash flow from operating  activities                                    |       | 72               |       | 77               |       | (6                | )          |
| Net income                                                                          |       | 106.3            |       | 56.6             |       | 88                |       |
| Per unit                                                                            |       | $                | 0.51       |             | $          | 0.28              |       | 82 |   |
| Prices                                                                              |       |             |       |             |       |              |       |
| WTI (US$/bbl)                                                                       |       | 90.63            |       | 60.22            |       | 50                |       |
| USD/CAD exchange rate                                                               |       | 1.02             |       | 0.87             |       | 17                |       |
| Realized oil price (CDN $/bbl)                                                      |       | 77.53            |       | 58.26            |       | 33                |       |
| AECO gas monthly index (CDN $/mcf)                                                  |       | 6.00             |       | 6.36             |       | (6                | )          |
| Realized gas price (CDN $/mcf)                                                      |       | 6.32             |       | 6.99             |       | (10               | )          |
| Operating netback ($/boe)                                                           |       |             |       |             |       |              |       |
| Revenue, before hedging                                                             |       | 57.42            |       | 49.94            |       | 15                |       |
| Royalties                                                                           |       | (10.46           | )          | (8.80            | )          | 19                |       |
| Transportation                                                                      |       | (0.69            | )          | (0.64            | )          | 8                 |       |
| Operating costs                                                                     |       | (9.64            | )          | (9.13            | )          | 6                 |       |
| Netback (before hedging)                                                            |       | 36.63            |       | 31.37            |       | 17                |       |
| Cash hedging gain (loss)                                                            |       | (0.20            | )          | 1.68             |       | (112              | )          |
| Netback (after hedging)                                                             |       | $                | 36.43      |             | $          | 33.05             |       | 10 |   |
| Capital expenditures                                                                |       | 139.3            |       | 121.9            |       | 14                |       |
| Capital funded with cash flow from  operating activities (per cent)                 |       | 32               |       | 28               |       | 14                |       |

 

CRITICAL ACCOUNTING ESTIMATES

 

The Trust has continuouslyevolved and documented its management and internal reporting systems to provideassurance that accurate, timely internal and external information is gatheredand disseminated.

 

The Trust’s financial andoperating results incorporate certain estimates including:

 

·                  estimated revenues,royalties and operating costs on production as at a specific reporting date butfor which actual revenues and costs have not yet been received;

 

·                  estimated capitalexpenditures on projects that are in progress;

 

·                  estimated depletion,depreciation and accretion that are based on estimates of oil and gas reservesthat the Trust expects to recover in the future;

 

·                  estimated fair values ofderivative contracts that are subject to fluctuation depending upon theunderlying commodity prices and foreign exchange rates;

 

·                  estimated value of assetretirement obligations that are dependent upon estimates of future costs andtiming of expenditures; and

 

·                  estimated futurerecoverable value of property, plant and equipment and goodwill.

 

The Trust has hired individualsand consultants who have the skills required to make such estimates and ensuresthat individuals or departments with the most knowledge of the activity areresponsible for the estimates. Further, past estimates are reviewed andcompared to actual results, and actual results are compared to budgets in orderto make more informed decisions on future estimates.

 

The ARC leadership team’smandate includes ongoing development of procedures, standards and systems toallow ARC staff to make the best decisions possible and ensuring thosedecisions are in compliance with the Trust’s environmental, health and safetypolicies.

 

22

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DISCLOSURE CONTROLS AND PROCEDURES

 

As of December 31, 2007,an internal evaluation was carried out of the effectiveness of the Trust’sdisclosure controls and procedures as defined in Rule 13a-15 under the USSecurities Exchange Act of 1934 and as defined in Canada by MultilateralInstrument 52-109, Certification of Disclosure in Issues’ Annual and InterimFilings. Based on that evaluation, the President and Chief Executive Officerand the Senior Vice President Finance and Chief Financial Officer concludedthat the disclosure controls and procedures are effective to ensure that theinformation required to be disclosed in the reports that the Trust files orsubmits under the Exchange Act or under Canadian Securities legislation isrecorded, processed, summarized and reported, within the time periods specifiedin the rules and forms therein. Disclosure controls and proceduresinclude, without limitation, controls and procedures designed to ensure thatthe information required to be disclosed by the Trust in the reports that itfiles or submits under the Exchange Act or under Canadian Securitieslegislation is accumulated and communicated to the Trust’s management,including the senior executive and financial officers, as appropriate to allowtimely decisions regarding the required disclosure.

 

INTERNAL CONTROL OVER FINANCIAL REPORTING

 

Internal control over financialreporting is a process designed to provide reasonable assurance that all assetsare safeguarded, transactions are appropriately authorized and to facilitatethe preparation of relevant, reliable and timely information. Because of itsinherent limitations, internal control over financial reporting may not preventor detect misstatements. Management has assessed the effectiveness of thecompany’s internal control over financial reporting as defined in Rule 13a-15under the US Securities Exchange Act of 1934 and as defined in Canada byMultilateral Instrument 52-109, Certification of Disclosure in Issues’ Annualand Interim Filings. The assessment was based on the framework in InternalControl – Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission. Management concluded that the Trust’sinternal control over financial reporting was effective as of December 31,2007. The effectiveness of the Trust’s internal control over financialreporting as of December 31, 2007 has been audited by Deloitte &Touche LLP, as reflected in their report for 2007. No changes were made to ourinternal control over financial reporting during the year-ended December 31,2007, that have materially affected, or are reasonably likely to materiallyaffect, our internal control over financial reporting.

 

FINANCIAL REPORTING UPDATE

 

During 2007, the Trust completedthe implementation of the new CICA Handbook Section 1530, ComprehensiveIncome, Section 3251, Equity, Section 3855, Financial Instruments –Recognition and Measurement, Section 3861, Financial Instruments –Disclosure and Presentation, and Section 3865, Hedges that deal with thepresentation of equity, recognition, measurement, disclosure, and presentationof financial instruments, and comprehensive income. As required by the newstandards, adoption has been applied prospectively as at January 1, 2007and prior periods have not been restated. The adoption of these standards hashad no material impact on the Trust’s Net Income or Cash Flows. See notes 3 and11 in the Notes to the Consolidated Financial Statements for further details.

 

Accounting Changes

 

Section 1506 permitsvoluntary changes in accounting policy only if they result in financialstatements that provide more reliable and relevant information. Changes inpolicy are applied retrospectively unless it is impractical to determine theperiod or cumulative impact of the change. Corrections of prior period errorsare applied retrospectively and changes in accounting estimates are appliedprospectively by including these changes in net income. In addition, disclosureis required for all future accounting changes when an entity has not applied anew source of GAAP that has been issued but is not yet effective.

 

23

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Future Accounting Changes

 

On December 1, 2006, theCICA issued three new accounting standards: Handbook Section 1535, CapitalDisclosures, Section 3862, Financial Instruments – Disclosures, and Section 3863,Financial Instruments – Presentation. These new standards will be effective on January 1,2008.

 

Section 1535 specifies thedisclosure of an entity’s objectives, policies and processes for managingcapital, quantitative data about what the entity regards as capital, whetherthe entity has complied with any capital requirements, and if it has notcomplied, the consequences of such non-compliance. This Section isexpected to have minimal impact on the Trust’s financial statements.

 

Sections 3862 and 3863 specifystandards of presentation and enhanced disclosure on financial instruments.Increased disclosure will be required on the nature and extent of risks arisingfrom financial instruments and how the entity manages those risks.

 

In February 2008, the CICAissued Section 3064, Goodwill and Intangible Assets, replacing Section 3062,Goodwill and Other Intangible Assets and Section 3450, Research andDevelopment Costs. The new Section will be effective on January 1,2009. Section 3064 establishes standards for the recognition, measurement,presentation and disclosure of goodwill and intangible assets subsequent to itsinitial recognition. Standards concerning goodwill are unchanged from thestandards included in the previous Section 3062. The Trust is currentlyevaluating the impact of the adoption of this new Section, however does notexpect a material impact on its Consolidated Financial Statements.

 

Update on Legislation ChangesImpacting the Trust

 

BROAD-BASED FEDERAL TAX REDUCTIONS

 

On October 30, 2007 theFederal Government presented the fall economic statement that proposedsignificant reductions in corporate income tax rates from 22.1 per cent to 15per cent. The reductions will be phased in between 2008 and 2012. In addition,the Government announced that it plans to collaborate with the provinces andterritories to reach a 25 per cent combined federal-provincial-territorialstatutory corporate income tax rate. The reduction in the federal rate willalso reduce the SIFT tax rate to 28 per cent as compared to the rate of 31.5per cent previously announced.

 

ALBERTA GOVERNMENT ROYALTY REGIME

 

In September 2007, theAlberta Government announced the results of the royalty review that wasperformed by an independent panel and on October 25, 2007, the AlbertaGovernment announced The New Royalty Framework, (“framework”), which will takeeffect on January 1, 2009 and is projected by the government to increaseroyalties by approximately $1.4 billion in 2010 or an increase of 20 per centover revenue forecasts by the Alberta Government for that year. Subsequent tothat time the Alberta Government has made some concessions to the proposedroyalty increases and industry is still awaiting final legislation in order tofully assess the impact. Our understanding is that at current commodity pricesthe increases comprise an average 57 per cent increase in conventional oilroyalties and a 10 per cent increase in gas royalties. The maximum royaltyrates are increasing from the current maximums of 30 per cent and 35 per centfor old and new tier rates respectively to rates that will range up to 50 percent.

 

The framework proposes new,simplified royalty formulas for conventional oil and natural gas that willoperate on sliding scales which are determined by commodity prices and wellproductivity. The formulas eliminate the conventional oil and natural gas tiersand several royalty exemption and relief programs. Enhanced Oil Recovery andInnovative Energy Technology Program Royalty relief programs have beenretained.

 

FEDERAL GOVERNMENT’S TRUST TAXLEGISLATION

 

In 2007, the Federal Governmentintroduced and passed into law Trust taxation that will result in a tax of 29.5per cent (previously 31.5 per cent as discussed above) on all Trustdistributions commencing January 1, 2011. Cash flow earned by the Trustand not distributed has always been and continues to form part of taxableincome at the Trust level, which may result in cash taxes being paid if thereare not sufficient tax pool claims and deductions obtained upon incurringcapital expenditures or acquiring assets.

 

The Trust recorded a $35.6million one time increase in earnings and a corresponding decrease to itsfuture income tax liability as a result of timing differences within the Trustthat have not been previously recognized as the Trust’s tax pools were inexcess of the net book value of the Trust’s assets. The initial recognition of$35.6 million comprises $24.7 million for pre-2007 generated temporarydifferences and $10.9 million for temporary differences relating to the currentyear. This amount was recorded in the second quarter results and is reflectedin the 2007 year-to-date results.

 

24

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CLIMATE CHANGE PROGRAMS

 

On March 8, 2007, theAlberta government introduced legislation to reduce greenhouse gas emissionintensity. Bill 3 states that facilities emitting more than 100,000 tonnes ofgreenhouse gases per year must reduce their emissions intensity by 12 per centover the average emissions levels of 2003, 2004 and 2005; if they are not ableto do so, these facilities are required to pay $15 per tonne for every tonneabove the 12 per cent target, effective as of July 1, 2007. At this time,the Trust has determined that the impact of this legislation would be minimalbased on ARC’s existing facilities ownership.

 

In April 2007, the FederalGovernment announced a new climate change plan that calls for greenhouse gasemissions to be reduced by 20 per cent below current levels by 2020. Firms mayemploy the following strategies to achieve the targets. They will be able to:

 

·                  make in-house reductions;

 

·                  take advantage ofdomestic emissions trading;

 

·                  purchase offsets;

 

·                  use the Clean DevelopmentMechanism under the Kyoto Protocol; and

 

·                  invest in a technologyfund.

 

The Trust is waiting foradditional information so as to fully assess what impact, if any, this newlegislation will have on its operations.

 

On January 24, 2008 theAlberta Government announced their plan to reduce projected emissions in theprovince by 50 per cent under the new climate change plan by 2050. This willresult in real reductions of 14 per cent below 2005 levels. The AlbertaGovernment stated they will form a government-industry council to determine ago-forward plan for implementing technologies, which will significantly reducegreenhouse gas emissions by capturing air emissions from industrial sources andlocking them permanently underground in deep rock formations.

 

In addition the plan calls forenergy conservation by individuals and for increased investment in clean energytechnologies and incentives for expanding the use of renewable and alternativeenergy sources such as bioenergy, wind, solar power, hydrogen and geothermalenergy. Initiatives under this theme will account for 18 per cent of Alberta’sreductions. A detailed implementation plan will be developed and released inthe spring of 2008.

 

UNITED STATES PROPOSED CHANGES TOQUALIFYING DIVIDENDS

 

A bill was introduced intoUnited States Congress on March 23, 2007 that could deny qualifieddividend income treatment to the distributions made by the Trust to its U.S.unitholders. The bill is in the first step of the legislative process and it isuncertain whether it will eventually be passed into law in its current form. Ifthe bill is passed in its current form, distributions received by U.S.unitholders would no longer qualify for the 15 per cent qualified dividend taxrate.

 

2007 REVIEW AND 2008 GUIDANCE

 

Following is a summary of theTrust’s 2008 Guidance issued by way of news release on November 7, 2007(posted on www.sedar.com) and a review of 2007 actual results compared to 2007Guidance:

 
| ** **                                                 | ** ** | **2007**              | ** ** | ** **                 | ** ** | ** **   | ** ** | **2008**     | ** ** |
|------------------------------------------------------------|------------|-----------------------|------------|----------------------------|------------|--------------|------------|--------------|------------|
| ** **                                                 | ** ** | **Guidance (1)** | ** ** | **Actual 2007 ** | ** ** | **% Change** | ** ** | **Guidance** | ** ** |
| Production (boe/d)                                         |       | 63,000                |       | 62,723                     |       | —       |       | 63,000       |       |
| Expenses ($/boe):                                          |       |                  |       |                       |       |         |       |         |       |
| Operating costs                                            |       | 9.50                  |       | 9.54                       |       | —       |       | 10.20        |       |
| Transportation                                             |       | 0.70                  |       | 0.72                       |       | 3            |       | 0.80         |       |
| G&A expenses (2)                                       |       | 2.25                  |       | 2.15                       |       | (4           | )          | 2.55         |       |
| Interest                                                   |       | 1.70                  |       | 1.61                       |       | (5           | )          | 1.90         |       |
| Capital expenditures ($ millions)(3)                  |       | 350                   |       | 397                        |       | 13           |       | 395          |       |
| Weighted average trust units and units issuable (millions) |       | 210                   |       | 210                        |       | —       |       | 216          |       |

 

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(1)                  2007 Guidance shown is therevised amounts from the Trust’s third quarter MD&A.

 

(2)                  G&A expenses originallysplit out non-cash expenses with a guidance estimate of $0.10 per boe comparedto actual results of $0.14 per boe.

 

(3)                  2008 Capital ExpenditureGuidance was revised on January 8, 2008. The additional $40 million isearmarked for the Trust’s Montney resource play.

 

25

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The 2008 Guidance is issued toprovide unitholders with information as to management’s expectations forresults of operations for 2008. Readers are cautioned that the 2008 Guidancemay not be appropriate for other purposes.

 

Actual 2007 results were inline with 2007 guidance with only minor exceptions as follows:

 

·                  Transportation costs werehigher than guidance due to additional trucking costs incurred in the fourthquarter in the Saskatchewan areas.

 

·                  Cash G&A expenseswere lower than guidance due to higher operating recoveries attributed to highlevels of capital and operating activity in the fourth quarter. This was offsetby non-cash G&A expenses that were higher than guidance as a result of anincrease in the Trust’s performance multiplier at year-end.

 

·                  Interest expense wasslightly lower than guidance due to the fact that the majority of the Trust’sdebt is denominated in U.S. dollars. With the strengthening of the Canadiandollar throughout 2007, the Trust’s Canadian equivalent of U.S. dollar interestpayments was reduced.

 

·                  Capital expendituresexceeded guidance by $47 million, which comprised unbudgeted purchases of landin the Dawson area of British Columbia in the third and fourth quarters of 2007for $71.3 million that were offset by cost savings of approximately $20 millionon the Trust’s original 2007 capital budget amount.

 

2008 OPERATING INCOME SENSITIVITY

 

Below is a table thatillustrates sensitivities to pre-hedged operating income items with operationalchanges and changes to the business environment:

 
| ** **                            | ** ** | **Impact on Annual Cash Flow  from Operating Activities (2)** | ** ** |
|---------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| **Business Environment**         | ** ** | **Assumption**                                                                                   | ** ** | **Change** | ** ** | **$ /Unit** | ** ** |
| Oil price (US$WTI/bbl) (1)            |       | $                                                                                                | 85.00      |   | $ | 1.00 |   | $ | 0.04 |   |
| Natural gas price (CDN $AECO/mcf) (1) |       | $                                                                                                | 6.50       |   | $ | 0.10 |   | $ | 0.03 |   |
| USD/CAD exchange rate                 |       | 1.03                                                                                             |       | $ | 0.01 |   | $ | 0.05 |   |
| Interest rate on debt                 |       | %                                                                                                | 5.75       |   | % | 1.0 |   | $ | 0.02 |   |
| Operational                           |       |                                                                                             |       |   |   |   |   |   |
| Liquids production volume (bbl/d)     |       | 32,100                                                                                           |       | % | 1.0 |   | $ | 0.03 |   |
| Gas production volumes (mmcf/d)       |       | 185.0                                                                                            |       | % | 1.0 |   | $ | 0.02 |   |
| Operating expenses per boe            |       | $                                                                                                | 10.20      |   | % | 1.0 |   | $ | 0.01 |   |
| Cash G&A expenses per boe         |       | $                                                                                                | 2.55       |   | % | 10.0 |   | $ | 0.03 |   |
|                                       |            |                                                                                                  |            |  |  |  |  |  |  |  |  |  |

 

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(1)                  Analysis does not include theeffect of hedging contracts.

 

(2)                  Assumes constant workingcapital.

 

ASSESSMENT OF BUSINESS RISKS

 

The ARC management team isfocused on long-term strategic planning and has identified the key risks,uncertainties and opportunities associated with the Trust’s business that canimpact the financial results as follows:

 

Changes In Tax And RoyaltyLegislation

 

Income tax laws, or other laws,or provincial royalty programs relating to the oil and gas industry may in thefuture be changed or interpreted in a manner that adversely affects the Trustor its Unitholders. Tax authorities having jurisdiction over the Trust orUnitholders may disagree with how the Trust calculates its income for tax purposesor how we calculate payment of crown royalties or could change administrativepractices to the detriment of the Trust and its Unitholders.

 

On October 31, 2006, theFinance Minister announced the federal government’s plan regarding the taxationof Income Trusts. Currently, distributions paid to unitholders, other thanreturns of capital, are claimed as a deduction by the Trust in arriving attaxable income whereby tax is eliminated at the Trust level and is paid by theunitholders. The Trust tax legislation which received Royal Assent on June 22,2007, will result in a two-tiered tax structure whereby distributions wouldfirst be subject to the federal corporate income tax rate plus a deemed 13 percent Provincial income tax at the Trust level commencing in 2011 (or earlier,if trusts that were publicly traded as of October 31, 2006 exceed thenormal growth guidelines announced by the Minister on December 15, 2006),and then unitholders would be subject to tax on the distribution as if it werea taxable dividend paid by a taxable Canadian corporation.

 

26

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In September 2007, theAlberta Government announced the results of the royalty review that wasperformed by an independent panel and on October 25, 2007, the AlbertaGovernment announced The New Royalty Framework, (“framework”), which will takeeffect on January 1, 2009 and is projected by the government to increaseroyalties by approximately $1.4 billion in 2010 or an increase of 20 per centover revenue forecasts by the Alberta Government for that year. Subsequent tothat time the Alberta government has made some concessions to the proposedroyalty increases and industry is still awaiting final legislation in order tofully assess the impact. Our understanding is that at current commodity pricesthe increases comprise an average 57 per cent increase in conventional oilroyalties and a 10 per cent increase in gas royalties. The maximum royaltyrates increasing from the current maximums of 30 per cent and 35 per cent forold and new tier rates respectively to rates that will range up to 50 per cent.

 

Access To Capital Markets

 

To the extent that externalsources of capital, including the issuance of additional trust units becomelimited or unavailable, ARC’s ability to make the necessary capital investmentsto maintain or expand its oil and natural gas reserves could be impaired. Tothe extent that ARC is required to use cash flow to finance capitalexpenditures or property acquisitions, the level of distributions could bereduced.

 

Volatility Of Oil And NaturalGas Prices

 

The Trust’s operational resultsand financial condition, and therefore the amount of distributions paid to theunitholders will be dependent on the prices received for oil and natural gasproduction. Oil and gas prices have fluctuated widely during recent years andare determined by economic and in some circumstances, political factors. Supplyand demand factors, including weather and general economic conditions as wellas conditions in other oil and natural gas regions impact prices. Any movementin oil and natural gas prices could have an effect on the Trust’s financialcondition and therefore on the distributions to the holders of trust units. ARCmay manage the risk associated with changes in commodity prices by enteringinto oil or natural gas price derivative contracts. If ARC engages inactivities to manage its commodity price exposure, the Trust may forego thebenefits it would otherwise experience if commodity prices were to increase. Inaddition, commodity derivative contracts activities could expose ARC to losses.To the extent that ARC engages in risk management activities related tocommodity prices, it will be subject to credit risks associated withcounterparties with which it contracts.

 

Variations In Interest RatesAnd Foreign Exchange Rates

 

Variations in interest ratescould result in an increase in the amount the Trust pays to service debt,resulting in a decrease in distributions to unitholders. World oil prices arequoted in US dollars and the price received by Canadian producers is thereforeaffected by the Canadian/US dollar exchange rate that may fluctuate over time.A material increase in the value of the Canadian dollar may negatively impactthe Trust’s net production revenue. In addition, the exchange rate for theCanadian dollar versus the US dollar has increased significantly over the last12 months, resulting in the receipt by the Trust of fewer Canadian dollars forits production, which may affect future distributions. ARC has initiatedcertain derivative contracts to attempt to mitigate these risks. To the extentthat ARC engages in risk management activities related to foreign exchangerates, it will be subject to credit risk associated with counterparties with whichit contracts. The increase in the exchange rate for the Canadian dollar andfuture Canadian/US exchange rates may impact future distributions and thefuture value of the Trust’s reserves as determined by independent evaluators.

 

Reserves Estimates

 

The reserves and recoveryinformation contained in ARC’s independent reserves evaluation is only anestimate. The actual production and ultimate reserves from the properties maybe greater or less than the estimates prepared by the independent reservesevaluator. The reserves report was prepared using certain commodity priceassumptions that are described in the notes to the reserves tables. If lowerprices for crude oil, natural gas liquids and natural gas are realized by theTrust and substituted for the price assumptions utilized in those reservesreports, the present value of estimated future net cash flows for the Trust’sreserves would be reduced and the reduction could be significant, particularlybased on the constant price case assumptions.

 

Depletion Of Reserves AndMaintenance Of Distribution

 

ARC’s future oil and naturalgas reserves and production, and therefore its cash flows, will be highlydependent on ARC’s success in exploiting its reserves base and acquiringadditional reserves. Without reserves additions through acquisition ordevelopment activities, the Trust’s reserves and production will decline overtime as the oil and natural gas reserves are produced out.

 

There can be no assurance thatthe Trust will make sufficient capital expenditures to maintain production atcurrent levels; nor as a consequence, that the amount of distributions by theTrust to unitholders can be maintained at current levels.

 

There can be no assurance thatARC will be successful in developing or acquiring additional reserves on termsthat meet the Trust’s investment objectives.

 

27

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Acquisitions

 

The price paid for reservesacquisitions is based on engineering and economic estimates of the reservesmade by independent engineers modified to reflect the technical views ofmanagement. These assessments include a number of material assumptionsregarding such factors as recoverability and marketability of oil, natural gas,natural gas liquids and sulphur, future prices of oil, natural gas, natural gasliquids and sulphur and operating costs, future capital expenditures androyalties and other government levies that will be imposed over the producinglife of the reserves. Many of these factors are subject to change and are beyondthe control of the operators of the working interests, management and theTrust. In particular, changes in the prices of and markets for oil, naturalgas, natural gas liquids and sulphur from those anticipated at the time ofmaking such assessments will affect the amount of future distributions and assuch the value of the units. In addition, all such estimates involve a measureof geological and engineering uncertainty that could result in lower productionand reserves than attributed to the working interests. Actual reserves couldvary materially from these estimates. Consequently, the reserves acquired maybe less than expected, which could adversely impact cash flows anddistributions to unitholders.

 

Environmental Concerns AndImpact On Enhanced Oil Recovery Projects

 

The oil and natural gasindustry is subject to environmental regulation pursuant to local, provincialand federal legislation. A breach of such legislation may result in theimposition of fines or issuance of clean up orders in respect of ARC or itsworking interests. Such legislation may be changed to impose higher standardsand potentially more costly obligations on ARC. Furthermore, managementbelieves the federal political parties, appear to favor new programs forenvironmental laws and regulation, particularly in relation to the reduction ofemissions, and there is no assurance that any such programs, laws orregulations, if proposed and enacted, will not contain emission reductiontargets which ARC cannot meet, and financial penalties or charges could beincurred as a result of the failure to meet such targets. In particular thereis uncertainty regarding the Federal Government’s Regulatory Framework for AirEmissions (“Framework”), as issued under the Canadian Environmental ProtectionAct.

 

Additionally,the potential impact on the Trust’s operations and business of the Framework,with respect to instituting reductions of greenhouse gases, is not possible toquantify at this time as specific measures for meeting Canada’s commitments havenot been developed. Currently, companies are permitted to emit CO2into the atmosphere with no requirement to capture and re-inject the emissions.In order for the Trust to carry out its enhanced oil recovery program it isnecessary to obtain CO2 at a cost effective rate. Given thatcompanies are not forced to capture their emissions, the infrastructure has notbeen put in place to facilitate this process. Without any additional provisionsfrom the government, the economic parameters of the Trust’s enhanced oilrecovery programs would be limited.

 

Although ARC has established areclamation fund for the purpose of funding its currently estimated futureenvironmental and reclamation obligations based on its current knowledge, therecan be no assurance that the Trust will be able to satisfy its actual futureenvironmental and reclamation obligations.

 

Operational Matters

 

The operation of oil and gaswells involves a number of operating and natural hazards that may result inblowouts, environmental damage and other unexpected or dangerous conditionsresulting in damage to operating subsidiaries of the Trust and possibleliability to third parties. ARC will maintain liability insurance, whereavailable, in amounts consistent with industry standards. Business interruptioninsurance may also be purchased for selected facilities, to the extent thatsuch insurance is available. ARC may become liable for damages arising fromsuch events against which it cannot insure or against which it may elect not toinsure because of high premium costs or other reasons. Costs incurred to repairsuch damage or pay such liabilities will reduce distributable cash.

 

Continuingproduction from a property, and to some extent the marketing of productionthere from, are largely dependent upon the ability of the operator of theproperty. Approximately 30 per cent of ARC’s production is operated by thirdparties. ARC has limited ability to influence costs on partner operatedproperties. Operating costs on most properties have increased steadily overrecent years. To the extent the operator fails to perform these functionsproperly, revenue may be reduced. Payments from production generally flowthrough the operator and there is a risk of delay and additional expense inreceiving such revenues if the operator becomes insolvent. Althoughsatisfactory title reviews are generally conducted in accordance with industrystandards, such reviews do not guarantee or certify that a defect in the chainof title may not arise to defeat the claim of the Trust to certain properties.A reduction of the distributions could result in such circumstances.

 

28

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Debt Service And AdditionalFinancing

 

Amounts paid in respect ofinterest and principal on debt will reduce distributions. Variations ininterest rates and scheduled principal repayments could result in significantchanges in the amount required to be applied to debt service before payment ofdistributions. Certain covenants of the agreements with ARC’s lenders may alsolimit distributions. Although ARC believes the credit facilities will besufficient for the Trust’s immediate requirements, there can be no assurancethat the amount will be adequate for the future financial obligations of theTrust or that additional funds will be able to be obtained.

 

The lenders have security oversubstantially all of the assets of ARC. If ARC becomes unable to pay its debtservice charges or otherwise commits an event of default such as bankruptcy,the lender may foreclose on or sell the working interests.

 

In thenormal course of making capital investments to maintain and expand the oil andgas reserves of the Trust, additional units are issued from treasury that mayresult in a decline in production per unit and reserves per unit. Additionally,from time to time the Trust issues units from treasury in order to reduce debtand maintain an optimal capital structure. Conversely, to the extent thatexternal sources of capital, including the issuance of additional units, becomelimited or unavailable, the Trust’s ability to make the necessary capitalinvestments to maintain or expand its oil and gas reserves may be impaired. Tothe extent that ARC is required to use cash flows to finance capitalexpenditures or property acquisitions, to pay debt service charges or to reducedebt, the level of distributable income will be reduced.

 

FORWARD-LOOKING STATEMENTS

 

This discussion and analysiscontains forward-looking statements as to the Trust’s internal projections,expectations or beliefs relating to future events or future performance withinthe meaning of the “safe harbour” provisions of the United States PrivateSecurities Litigation Reform Act of 1995 and the Securities Act (Ontario). Insome cases, forward-looking statements can be identified by terminology such as“may”, “will”, “should”, “expects”, “projects”, “plans”, “anticipates” andsimilar expressions and, in particular, includes the material under the heading“2007 Review and 2008 Guidance”. These statements represent management’sexpectations or beliefs concerning, among other things, future operatingresults and various components thereof or the economic performance of ARCEnergy Trust (“ARC” or “the Trust”). The projections, estimates and beliefscontained in such forward-looking statements are based on management’sassumptions relating to the production performance of ARC’s oil and gas assets,the cost and competition for services throughout the oil and gas industry in2007, the continuation of ARC’s historical experience with expenses andproduction, changes in the capital expenditure budgets relating to undevelopedland or reserve acquisitions. and the continuation of the current regulatoryand tax regime in Canada, and necessarily involve known and unknown risks anduncertainties, including the business risks discussed in this MD&A, andrelated to management’s assumptions set forth herein, which may cause actualperformance and financial results in future periods to differ materially fromany projections of future performance or results expressed or implied by suchforward-looking statements. Accordingly, readers are cautioned that events orcircumstances could cause actual results to differ materially from thosepredicted. Other than the 2008 Guidance which is updated and discussedquarterly, the Trust does not undertake to update any forward lookinginformation in this document whether as to new information, future events orotherwise except as required by securities laws and regulations.

 

ADDITIONAL INFORMATION

 

Additional information relatingto ARC can be found on SEDAR at www.sedar.com.

 

29

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Annual Historical Review

 
| **For the year ended December 31**                 | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|-----------------------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|
| **(CDN $ millions, except per unit amounts)** | ** ** | **2007**   | ** ** | **2006**   | ** ** | **2005**   | ** ** | **2004**   | ** ** | **2003**   | ** ** |
| Financial                                                                   |       |       |       |       |       |       |       |       |       |       |       |
| Revenue before royalties                                                    |       | 1,251.6    |       | 1,230.5    |       | 1,165.2    |       | 901.8      |       | 743.2      |       |
| Per unit (1)                                                                |       | 5.95       |       | 6.02       |       | 6.10       |       | 4.85       |       | 4.80       |       |
| Cash flow from operating activities (2)                                     |       | 704.9      |       | 734.0      |       | 616.7      |       | 446.4      |       | 405.3      |       |
| Per unit – basic (1)                                                   |       | 3.35       |       | 3.59       |       | 3.23       |       | 2.40       |       | 2.62       |       |
| Per unit – diluted                                                     |       | 3.35       |       | 3.58       |       | 3.20       |       | 2.38       |       | 2.54       |       |
| Net income                                                                  |       | 495.3      |       | 460.1      |       | 356.9      |       | 241.7      |       | 284.6      |       |
| Per unit – basic (3)                                                   |       | 2.39       |       | 2.28       |       | 1.90       |       | 1.32       |       | 1.88       |       |
| Per unit – diluted                                                     |       | 2.39       |       | 2.27       |       | 1.88       |       | 1.31       |       | 1.82       |       |
| Distributions                                                               |       | 498.0      |       | 484.2      |       | 376.6      |       | 330.0      |       | 279.3      |       |
| Per unit (4)                                                                |       | 2.40       |       | 2.40       |       | 1.99       |       | 1.80       |       | 1.80       |       |
| Total assets                                                                |       | 3,533.0    |       | 3,479.0    |       | 3,251.2    |       | 2,305.0    |       | 2,281.8    |       |
| Total liabilities                                                           |       | 1,491.3    |       | 1,550.6    |       | 1,415.5    |       | 755.7      |       | 730.0      |       |
| Net debt outstanding (5)                                                    |       | 752.7      |       | 739.1      |       | 578.1      |       | 264.8      |       | 262.1      |       |
| Weighted average trust units (millions) (6)                                 |       | 210.2      |       | 204.4      |       | 191.2      |       | 186.1      |       | 154.7      |       |
| Trust units outstanding and issuable at period end (millions) (6)           |       | 213.2      |       | 207.2      |       | 202.0      |       | 188.8      |       | 182.8      |       |
| Capital Expenditures                                                        |       |       |       |       |       |       |       |       |       |       |       |
| Geological and geophysical                                                  |       | 14.9       |       | 11.4       |       | 9.2        |       | 5.4        |       | 5.7        |       |
| Land                                                                        |       | 77.5       |       | 32.4       |       | 9.1        |       | 4.1        |       | 4.0        |       |
| Drilling and completions                                                    |       | 229.5      |       | 240.5      |       | 191.8      |       | 140.4      |       | 106.2      |       |
| Plant and facilities                                                        |       | 72.1       |       | 77.6       |       | 55.0       |       | 41.1       |       | 36.5       |       |
| Other capital                                                               |       | 3.2        |       | 2.6        |       | 3.7        |       | 2.8        |       | 3.4        |       |
| Total capital expenditures                                                  |       | 397.2      |       | 364.5      |       | 268.8      |       | 193.8      |       | 155.8      |       |
| Property acquisitions (dispositions), net                                   |       | 42.5       |       | 115.2      |       | 91.3       |       | (58.2      | )          | (161.6     | )          |
| Corporate acquisitions (7)                                                  |       | —     |       | 16.6       |       | 505.0      |       | 72.0       |       | 721.6      |       |
| Total capital expenditures and net acquisitions                             |       | 439.7      |       | 496.3      |       | 865.1      |       | 207.6      |       | 715.8      |       |
| Operating                                                                   |       |       |       |       |       |       |       |       |       |       |       |
| Production                                                                  |       |       |       |       |       |       |       |       |       |       |       |
| Crude oil (bbl/d)                                                           |       | 28,682     |       | 29,042     |       | 23,282     |       | 22,961     |       | 22,886     |       |
| Natural gas (mmcf/d)                                                        |       | 180.1      |       | 179.1      |       | 173.8      |       | 178.3      |       | 164.2      |       |
| Natural gas liquids (bbl/d)                                                 |       | 4,027      |       | 4,170      |       | 4,005      |       | 4,191      |       | 4,086      |       |
| Total (boe per day 6:1)                                                     |       | 62,723     |       | 63,056     |       | 56,254     |       | 56,870     |       | 54,335     |       |
| Average prices                                                              |       |       |       |       |       |       |       |       |       |       |       |
| Crude oil ($/bbl)                                                           |       | 69.24      |       | 65.26      |       | 61.11      |       | 47.03      |       | 36.90      |       |
| Natural gas ($/mcf)                                                         |       | 6.75       |       | 6.97       |       | 8.96       |       | 6.78       |       | 6.40       |       |
| Natural gas liquids ($/bbl)                                                 |       | 54.79      |       | 52.63      |       | 49.92      |       | 39.04      |       | 32.19      |       |
| Oil equivalent ($/boe)                                                      |       | 54.54      |       | 53.33      |       | 56.54      |       | 43.13      |       | 37.29      |       |
| Reserves (company interest) (8)                                             |       |       |       |       |       |       |       |       |       |       |       |
| Proved plus probable reserves                                               |       |       |       |       |       |       |       |       |       |       |       |
| Crude oil and NGL (mbbl)                                                    |       | 158,341    |       | 162,193    |       | 163,385    |       | 123,226    |       | 129,663    |       |
| Natural gas (bcf)                                                           |       | 768.2      |       | 743.6      |       | 741.7      |       | 724.5      |       | 720.2      |       |
| Total (mboe)                                                                |       | 286,370    |       | 286,125    |       | 286,997    |       | 243,974    |       | 249,704    |       |
| Trust Unit Trading (based on  intra-day trading) Unit prices                |       |       |       |       |       |       |       |       |       |       |       |
| High                                                                        |       | 23.86      |       | 30.74      |       | 27.58      |       | 17.98      |       | 14.87      |       |
| Low                                                                         |       | 18.90      |       | 19.20      |       | 16.55      |       | 13.50      |       | 10.89      |       |
| Close                                                                       |       | 20.40      |       | 22.30      |       | 26.49      |       | 17.90      |       | 14.74      |       |
| Average daily volume (thousands)                                            |       | 597        |       | 706        |       | 656        |       | 420        |       | 430        |       |

 

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(1)                  Per unit amounts (with theexception of per unit distributions) are based on weighted average trust unitsoutstanding plus trust units issuable for exchangeable shares.

 

(2)                  This is a GAAP measure and achange from the non-GAAP measure reported in prior quarters. Refer to non-GAAPsection.

 

(3)                  Net income per unit is based onnet income after non-controlling interest divided by weighted average trustunits outstanding (excluding trust units issuable for exchangeable shares).

 

(4)                  Based on number of trust unitsoutstanding at each distribution date.

 

30

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(5)                  Net debt excludes the currentunrealized risk management contracts asset and liability and the currentportion of future income taxes.

 

(6)                  Includes trust units issuablefor outstanding exchangeable shares based on the period end exchange ratio.

 

(7)                  Represents total considerationfor the corporate acquisition including fees but prior to working capital,asset retirement obligation and future income tax liability assumed onacquisition.

 

(8)                  Company interest reserves arethe gross interest reserves plus the royalty interest prior to the deduction ofroyalty burdens.

 

Quarterly Historical Review

 
| ** **                                                     | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
|----------------------------------------------------------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|------------|
| **(CDN $ millions,**                                 | ** ** | **2007**   | ** ** | **2006**   | ** ** |
| **except per unit amounts)**                    | ** ** | **Q4**     | ** ** | **Q3**     | ** ** | **Q2**     | ** ** | **Q1**     | ** ** | **Q4**     | ** ** | **Q3**     | ** ** | **Q2**     | ** ** | **Q1**     | ** ** |
| Financial                                                      |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |
| Revenue before royalties                                       |       | 338.0      |       | 300.2      |       | 305.6      |       | 307.8      |       | 292.5      |       | 312.3      |       | 306.7      |       | 318.9      |       |
| Per unit (1)                                                   |       | 1.59       |       | 1.42       |       | 1.46       |       | 1.48       |       | 1.42       |       | 1.52       |       | 1.51       |       | 1.58       |       |
| Cash flow from operating activities (2)                        |       | 173.7      |       | 179.6      |       | 179.4      |       | 172.3      |       | 159.4      |       | 203.4      |       | 182.2      |       | 189.0      |       |
| Per unit – basic (1)                                      |       | 0.82       |       | 0.85       |       | 0.86       |       | 0.83       |       | 0.77       |       | 0.99       |       | 0.89       |       | 0.93       |       |
| Per unit – diluted                                        |       | 0.82       |       | 0.85       |       | 0.86       |       | 0.83       |       | 0.77       |       | 0.98       |       | 0.89       |       | 0.93       |       |
| Net income                                                     |       | 106.3      |       | 120.8      |       | 184.9      |       | 83.3       |       | 56.6       |       | 116.9      |       | 182.5      |       | 104.1      |       |
| Per unit – basic (3)                                      |       | 0.51       |       | 0.58       |       | 0.90       |       | 0.41       |       | 0.28       |       | 0.58       |       | 0.91       |       | 0.52       |       |
| Per unit – diluted                                        |       | 0.51       |       | 0.58       |       | 0.89       |       | 0.41       |       | 0.28       |       | 0.58       |       | 0.91       |       | 0.52       |       |
| Distributions                                                  |       | 125.8      |       | 125.0      |       | 124.1      |       | 123.1      |       | 122.3      |       | 121.4      |       | 120.6      |       | 119.9      |       |
| Per unit (4)                                                   |       | 0.60       |       | 0.60       |       | 0.60       |       | 0.60       |       | 0.60       |       | 0.60       |       | 0.60       |       | 0.60       |       |
| Total assets                                                   |       | 3,533.0    |       | 3,460.8    |       | 3,432.8    |       | 3,540.1    |       | 3,479.0    |       | 3,335.8    |       | 3,277.8    |       | 3,279.7    |       |
| Total liabilities                                              |       | 1,491.3    |       | 1,421.4    |       | 1,415.3    |       | 1,526.6    |       | 1,550.6    |       | 1,371.3    |       | 1,339.9    |       | 1,434.1    |       |
| Net debt outstanding (5)                                       |       | 752.7      |       | 699.8      |       | 653.9      |       | 729.7      |       | 739.1      |       | 579.7      |       | 567.4      |       | 598.9      |       |
| Weighted average trust units (6)                               |       | 212.5      |       | 210.9      |       | 209.5      |       | 207.9      |       | 206.5      |       | 205.1      |       | 203.7      |       | 202.5      |       |
| Trust units outstanding and  issuable (6)                      |       | 213.2      |       | 211.7      |       | 210.2      |       | 208.7      |       | 207.2      |       | 205.7      |       | 204.4      |       | 203.1      |       |
| Capital Expenditures                                           |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |
| Geological and geophysical                                     |       | 3.0        |       | 2.9        |       | 4.1        |       | 4.9        |       | 3.7        |       | 2.2        |       | 2.8        |       | 2.7        |       |
| Land                                                           |       | 42.6       |       | 33.0       |       | 1.7        |       | 0.2        |       | 11.8       |       | 1.4        |       | 14.3       |       | 4.9        |       |
| Drilling and completions                                       |       | 75.2       |       | 73.4       |       | 25.8       |       | 55.1       |       | 79.1       |       | 76.2       |       | 29.8       |       | 55.4       |       |
| Plant and facilities                                           |       | 17.9       |       | 21.1       |       | 16.3       |       | 16.8       |       | 26.5       |       | 24.6       |       | 10.9       |       | 15.6       |       |
| Other capital                                                  |       | 0.6        |       | 1.5        |       | 0.6        |       | 0.5        |       | 0.8        |       | 0.5        |       | 0.8        |       | 0.5        |       |
| Total capital expenditures                                     |       | 139.3      |       | 131.9      |       | 48.5       |       | 77.5       |       | 121.9      |       | 104.9      |       | 58.6       |       | 79.1       |       |
| Property acquisitions (dispositions) net                       |       | 5.0        |       | 27.3       |       | 10.0       |       | 0.2        |       | 76.4       |       | 8.4        |       | 2.8        |       | 27.6       |       |
| Corporate acquisitions (7)                                     |       | —     |       | —     |       | —     |       | —     |       | 16.6       |       | —     |       | —     |       | —     |       |
| Total capital expenditures and net acquisitions                |       | 144.3      |       | 159.2      |       | 58.5       |       | 77.7       |       | 214.9      |       | 113.3      |       | 61.4       |       | 106.7      |       |
| Operating                                                      |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |
| Production                                                     |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |
| Crude oil (bbl/d)                                              |       | 28,682     |       | 28,437     |       | 28,099     |       | 29,520     |       | 29,605     |       | 29,108     |       | 27,805     |       | 29,651     |       |
| Natural gas (mmcf/d)                                           |       | 187.4      |       | 173.3      |       | 176.7      |       | 183.0      |       | 179.5      |       | 173.4      |       | 178.5      |       | 185.0      |       |
| Natural gas liquids (bbl/d)                                    |       | 4,067      |       | 3,795      |       | 4,088      |       | 4,161      |       | 4,144      |       | 4,166      |       | 4,247      |       | 4,120      |       |
| Total (boe per day 6:1)                                        |       | 63,989     |       | 61,108     |       | 61,637     |       | 64,175     |       | 63,663     |       | 62,178     |       | 61,803     |       | 64,600     |       |
| Average prices                                                 |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |
| Crude oil ($/bbl)                                              |       | 77.53      |       | 73.40      |       | 65.21      |       | 60.79      |       | 58.26      |       | 71.84      |       | 71.86      |       | 59.53      |       |
| Natural gas ($/mcf)                                            |       | 6.32       |       | 5.52       |       | 7.38       |       | 7.75       |       | 6.99       |       | 6.10       |       | 6.35       |       | 8.40       |       |
| Natural gas liquids ($/bbl)                                    |       | 62.75      |       | 55.64      |       | 52.76      |       | 48.04      |       | 46.51      |       | 56.60      |       | 54.44      |       | 52.91      |       |
| Oil equivalent ($/boe)                                         |       | 57.26      |       | 53.28      |       | 54.37      |       | 53.18      |       | 49.82      |       | 54.45      |       | 54.42      |       | 54.74      |       |
| Trust Unit Trading (based on  intra-day trading)   Unit prices |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |       |
| High                                                           |       | 21.55      |       | 22.60      |       | 23.86      |       | 23.02      |       | 29.22      |       | 30.74      |       | 28.61      |       | 27.51      |       |
| Low                                                            |       | 18.90      |       | 19.00      |       | 20.78      |       | 20.05      |       | 19.20      |       | 25.25      |       | 24.35      |       | 25.09      |       |
| Close                                                          |       | 20.40      |       | 21.17      |       | 21.74      |       | 21.25      |       | 22.30      |       | 27.21      |       | 28.00      |       | 27.36      |       |
| Average daily volume (thousands)                               |       | 624        |       | 503        |       | 599        |       | 658        |       | 1,125      |       | 614        |       | 548        |       | 546        |       |

 

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(1)                  Per unit amounts (with theexception of per unit distributions) are based on weighted average trust unitsoutstanding plus trust units issuable for exchangeable shares.

 

(2)                  This is a GAAP measure and achange from the non-GAAP measure reported in prior reports. Refer to non-GAAPsection.

 

(3)                  Net income per unit is based onnet income after non-controlling interest divided by weighted average trustunits outstanding (excluding trust units issuable for exchangeable shares).

 

(4)                  Based on number of trust unitsoutstanding at each distribution date.

 

(5)                  Net debt excludes the currentunrealized risk management contracts asset and liability and the currentportion of future income taxes.

 

(6)                  Includes trust units issuablefor outstanding exchangeable shares based on the period end exchange ratio.

 

(7)                  Represents total considerationfor the corporate acquisition including fees but prior to working capital,asset retirement obligation and future income tax liability assumed onacquisition.

 

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